Schlumberger Spe Papers

Nov-09 NOTES: The papers listed here have been obtained by search SPE and IPTC papers post 2005 on the SPE's OnePetro The papers relating to reservoir engineering have been catergorised for inclusion on the

reservoirengineering.org.uk website

The affiiations searched were;

BP Shell Chevron ConocoPhillips Marathon Total Schlumberger Imperial College, London Heriot Watt University, Edinburgh (Anywhere in Article) Total

Total number of papers published post 2005

Total No Papers 551 575 482 191 55 255 1130 95 235

Reservoir Engineering Related 175 279 238 68 37 129 563 53 175

3569

1717

10,000 35% of papers published categorised

Organisation SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

Paper Source No. SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE IPTC

115707 116422 116424 121970 108540 115247 98617 108528 102968 112259 98945 112365 119506 113843 107445 99720 98142 117622 112021 123773 103329 104755 107101 110968 111512 117066 126063 103900 109591 115485 99994 11556 110833 103242 100739 116501 121414 112977 102240 106375 11239 109539 123423 100393 108097 102571 110511 11582

Chapter CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 CO2 Corporate Process Drilling Drilling Drilling EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR EOR/IOR Flow Assurance Flow Assurance Flow Assurance Flow Assurance Flow Assurance Flow Assurance Flow Assurance Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE IPTC SPE SPE SPE SPE

122562 99386 109684 123430 89704 111911 108494 81481 120988 114702 115429 100937 11268 116098 118893 97886 101219 117164 110364 115499 101084 100865 11573 115622 12886 120468 120947 114058 122844 112434 122845 98220 114255 107993 100112 101401 100516 108994 126075 105069 117233 110401 118434 11395 97889 117682 12536 117689 103841 120423 102460

Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Fluid Description Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Formation Damage Giant Field Giant Field Giant Field Giant Field Giant Field Giant Field Giant Field Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE IPTC SPE

104163 104520 116746 105327 104046 117285 117562 107636 115609 103997 116243 121755 121759 106054 107108 120817 106712 98318 93805 107277 100182 121695 122197 113487 108075 120161 117570 120749 125237 126160 102956 119481 119140 119927 103865 123296 103250 90630 105681 90690 120424 11528 112303 11545 109565 115825 103987 110067 102569 12328 121223

Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil Heavy Oil HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT HP/HT Lab Testing Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs Low Permeability Reservoirs

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE IPTC IPTC IPTC SPE SPE SPE IPTC IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

101257 105262 101129 11537 11765 12502 106100 101897 116328 11622 12253 121945 108566 108925 105014 120407 97224 100351 101718 116591 119690 118380 110277 102888 110223 102256 110752 109848 102572 121923 120443 101343 101286 101913 115836 101126 102435 122585 109972 126044 116092 126094 95841 101721 102588 104013 105427 118895 103284 105456 102562

Low Permeability Reservoirs Low Permeability Reservoirs Minor Reservoirs Minor Reservoirs Project Management Project Management Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

116068 117073 110304 112385 107192 115822 110301 110803 89177 107241 120813 101176 93974 118152 100740 109683 11488 104018 11350 120691 100738 102456 102413 101556 101151 12029 104041 12225 126064 120803 99317 123711 122339 122421 102557 11594 100984 101491 121489 117633 112223 99469 109260 112209 102439 116218 120664 116528 99338 107702 103028

Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Development Reservoir Development Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE

108693 108737 98198 93444 110927 122338 105797 102084 99288 11718 101779 120433 99882 12665 102148 122768 119172 119165 110412 105700 112923 120050 126095 110219 119732 111457 99445 120552 102111 117445 99575 107853 107356 104015 106251 119352 103188 121612 112926 96260 123087 101138 107907 11205 66365 118709 101013 118979 117370 101674 95498

Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Management Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE IPTC IPTC SPE SPE SPE SPE SPE SPE IPTC SPE

115881 102549 107471 119132 121392 93324 100131 119605 121275 121488 106181 107511 122186 95750 100403 118909 96571 118850 105041 116063 102715 99240 11772 122478 100024 115712 100607 101310 101140 114027 117963 107119 100992 103589 105362 12108 115504 126158 93057 112429 110813 11262 11745 102159 104017 104021 115816 116914 90024 11971 122604

Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Modelling Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance Reservoir Performance SPE Forum State of the Nation State of the Nation State of the Nation Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE IPTC SPE SPE SPE SPE SPE SPE IPTC SPE

112221 11171 115976 121696 119361 94708 101886 110634 110064 116474 116286 102351 103757 11433 105166 114337 117892 111174 120558 102309 113600 107985 103232 103327 114974 103202 122934 117704 103514 119636 12368 126066 110103 106094 102544 12364 112476 112862 101720 102583 100834 110240 11630 84219 120744 126070 126061 102653 96722 12668 106050

Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Surveillence Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Unconventional Reservoirs Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

107979 112438 117061 119825 122307 103822 112435 125336 122514 108126 107604 112171 99419 118292 112442 114768 121204 121415 113562 101722 119300 115556 119635 107730 100572 105657 98338 100524 102677 119586 11150 11347 102326 110068 107662 102788 100556 102167 109909 109969 121888 98188 100321 106225 102469 106317 110696 106264 106043 102570 102405

Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE IPTC SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE IPTC SPE IPTC SPE SPE IPTC SPE SPE

98746 122018 12183 119351 104202 106854 113553 114961 112077 120800 123008 120799 110960 113918 103617 104629 116370 120049 105022 106400 102241 112488 104099 120508 101278 112432 113698 111538 119639 121931 121964 110978 112491 105541 117518 105542 128606 112456 105758 107297 121093 121834 121912 12448 98151 12581 123495 112050 12385 107440 102185

Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE SPE

112904 100944 104239 92715 102242 98315 101087 90383 106272 107978 115525 115528 98221 98357 105127 106321 106442 112419 116601 116775 109911 104610 106444 115558 104627 102681 107966 111431 98055 105367 112176 101420 109860 105134 110576 116969 104059 120515 123115 102575 123555 114594 109279 113650 118148 110873 116003 114127 115478 90992 101475

Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Deliverability Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing Well Testing

SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER SCHLUMBERGER

SPE SPE SPE SPE SPE

103223 105271 107967 103040 102106

Well Testing Well Testing Well Testing Well Testing Well Testing

Section Integrity Integrity Integrity Management Modelling - Injection Reservoir Description Storage Storage Workshop Paper PRODML ERD Field Re-development Horizontal Well CO2 Injection CO2 Source Heterogeneity Multilateral Sidetracks SAGD Optimisation Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Well Intervention Asphaltene Deposition Lab Testing Lab Testing Modelling - Integrated Asset Modelling - Well/Network Wax/Asphaltenes Waxy Crudes CO2 Detection CO2 Detection Core Testing Correlations Correlations Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Downhole Fluid Analysis Hydrogen Sulphide Detection

Subject

Modelling - Integrated Compositional Field Study

Capture/Storage Production Data Standards World Record Dumbarton Field Longest in World

Oligocene Vicksburg Formation Gas Condensate Easterm Venezuela Gas Shut-off Undeveloped Reservoirs Water Shut-off Water Shut-off Water Shut-off Water Shut-off Water Shut-off Water Shut-off Water Shut-off Risk Assurance Horizontal Pipes Inclined Pipes Production Alllocation San Manuel Asset Risk Reduction Deepwater WFT WFT Asphaltene Deposition Gas Condensate Gas Condensate Asphaltenes Case Study Continuous Log Neural Network Modelling OBM Clean-up Reservoir Architecture Reservoir management Reservoir management WFT

Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Insitu PVT Variations Methane Detection Modelling - Asphaltene Precipitation Modelling - Compositional Modelling - EOS Modelling - Fluid Analysis Modelling - Neural - Network Optical Fluid Analysis Phase Envelope Construction Production Chemistry PVT Analysis PVT Data PVT Data Sampling Sampling Sampling Sampling Sampling Acid Treatments Chelating Technology Core Testing Halite Inhibition Injection Water Quality Modelling - Formation Damage Perforation Induced Performation Damage Scale Control Scale Management Scale Management Scale Management Sulfate Stripping Modelling - History Matching Modelling - Streamline Modelling - Streamline Reservoir Performance Surveillence Surveillence Waterflood Management Artificial Lift Artificial Lift EOR/IOR EOR/IOR Minor Reservoirs Reservoir Description Reservoir Description

Downhole Fluid Analysis Gas Condensate Integrated Data Integrated Data Optical Spectroscopy Pressure Measurements Pressure/insitu Fluid measurements Downhole Measurement Development Impact Downhole Fluid Analysis Insitu PVT Variations Fluid comparison Algorithm Downhole Fluid Analysis Downhole Fluid Samples Non-Isothermal Heavy-oil Onsite Downhole Analysis WFT Carbonate Reservoir Contamination Detection Gas Condensate Multiphase Multiphase Meter Deep Wells Algyo Field Acid Treatment Horizontal Well Injectivitvity Naphthenate Induced Removal Stimulated Wells Case Study Intelligent Well Strontium Sulfate Gyda Field Identifying Flow Regions Fracture Characterisation Sabiriyah field Modelling - Heterogeneity Automation Waterflood Surveillence Cavity Pumps Downhole Heaters Assisted Gravity drainage SAG Development Carbonate Reservoir WFT

Reservoir Development Reservoir Development Stimulation Surveillence Thermal Recovery Well Testing Well Testing Acid Treatments Data Acquisition Exploration Process Fluid Description Fracturing Fluid Fracturing Fluid Lab Testing Perforation Methods Permanent DH Pressure Monitoring Propped Fracturing Stimulation Stimulation Surfactant Fracturing Water Block Prevention Water PH measurement Asphatene Precipitation Completion Completion/Stimulation Development Optimisation Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracturing Fracturing Horizontal Well Stimulation Horizontal Well Stimulation Horizontal Well Stimulation Horizontal Wells Modelling - Reservoir Performance Modelling - Single well Performance Modelling - Streamline Production Optimisation Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Description Reservoir Development Reservoir Management Reservoir Performance Surveillence Surveillence

Horizontal wells Steam Injection Chemical Treatment Production Logging Development Multiphase Meter Multiphase Meter Gas Condensate India Insitu PVT Variations

Acid Fracturing Coiled-Tubing-Conveyed Gas Well Vietnam Acid treatment

Laboratory Determination Capillary Flow Horizontal wells Horizontal wells Challenges Case study Impact of Pressure Depletion Microseismic Data Hybrid Fracturing Fiber Assisted Acid treatment Case Study Propped Fracturing Carbonate Reservoir Production Forecasting Optimised Completions Fluvial Reservoir Heterogeneity Formation Evaluation Fracture Characterisation Integrated Study Naturally Fractured Reservoirs Pressure Measurements Pressure Measurements WFT Heterogeneity Horizontal wells Reservoir Architecture Formation Evaluation Logging

Transition Zones Well Intervention Development Strategy Stimulation Decision Making Decision Making Borehole Image Interpretation Capillary Pressure Deep Electromagnetic Data Depositional Environment Depositional Environment Depositional Environment Downhole Fluid Analysis Downhole Fluid Analysis Flow Unit Characterisation Flow Unit Characterisation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation Formation Evaluation - Enhanced description Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Heterogeneity Formation Evaluation - Horizontal Injectors Formation Evaluation - Integrated Well Data Formation Evaluation - Unconsolidated Geomechanical Geo-Modelling Geostatistics Geostatistics Heterogeneity Heterogeneity LWD Interpretation LWD Interpretation LWD Interpretation Mechanism - Stress Orientation Modelling - Geomechanical Properties Modelling - Near Wellbore Stress Multi-Layered Reservoir Multi-Layered Reservoir Multi-Layered Reservoir Natural Fracture Characterisation Natural Fracture Characterisation Natural Fracture Characterisation Natural Fracture/Fault Characterisation Naturally Fractured Reservoirs

Carbonate Reservoir Water Shut-off Heterogeneity Mini Fracturing

Case Study Carbonate Reservoir Heterogeneity Borehole Images Borehole Images Integrated Well Data Reservoir Characterisation Reservoir Characterisation Carbonate Reservoir Deltaic Reservoir LWD LWD LWD vs Gamma Ray Shaly Sand Analysis Shaly Sand Analysis Workflow Carbonate and Clastic Reservoirs Carbonate Reservoir Deepwater Perforation Selection Turbidites LWD Modelling Cambrian Reservoirs Deepwater Carbonate Reservoirs Channel Deposition Kharaib Field Formation Evaluation Methods NMR Mediterranean Reservoirs

Horizontal Wells Prediction Algorithm PLT Interpretation PLT Interpretation PLT Interpretation Borehole Seismic Formation Evaluation Integrated Study Borehole Images Maloichskoe

Near Wellbore Flow Properties Near Wellbore Flow Properties Near Wellbore Flow Properties Near Wellbore Stress NMR Interpretation NMR Interpretation NMR Interpretation NMR Interpretation NMR Logging Oil Interval Detection PLT Interpretation Porosity/Permeability Analysis Productivity Interpretation Reservoir Architecture Reservoir Architecture Reservoir Architecture Reservoir Connectivity Reservoir Properties Residual Oil Saturation WFT WFT WFT WFT Integrated Study Uncertainty Management Artificial Lift EOR/IOR Gas Lift Optimisation Heterogeneity Heterogeneity Low Pressure Gas Methodology Modelling - Coupled Surface/Reservoir Model Modelling - Coupled Surface/Reservoir Model Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Modelling - Integrated Asset Produced Water Management Produced Water Management Production Optimisation Production Optimisation Productivity Improvement Reserves Evaluation Value of Information

Downhole Monitoring Downhole Monitoring Integrated Well Data Fractured Clastics Optimised WFT Sampling

Formation Evalustion Horizontal Wells Carbonate Reservoirs UBD Fracture Fairways Integrated Well Data Integrated Well Data Downhole Fluid Analysis PLT Interpretation Pulsed Neutron Decay Deltaic Reservoir Optimised Sampling Stress/Permeability Measurment Supercharging Betty Field Heterogeneity Selection Criteria Mature Fields Surveillence Well Placement Well Placement Optimisation Wellsite Compression Life of Field Production Optimisation SMART wells Development Optimisation Gas Lift Optimisation Production Optimisation Production Optimisation Steam Injection Uncertainty Management Workflow

XJG Fields Gas Lift Optimisation Mature Fields Integrated Study Lower Vicksburg Sands Framework

Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Well Placement Optimisation Adjoint Based Simulation Analytical Model Analytical Reservoir Model Analytical Well Performance Assisted HM Assisted HM Assisted HM Assisted HM Assisted HM Compaction Modelling Complex Physics Modelling Complex Physics Modelling Complex Well Modelling Complex Well Modelling Complex Well Modelling Complex Well Modelling Coupled Reservoir/Geomechanical Model Coupled Thermal/Composional Model Decline Curve analysis Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Modelling Fracture Spacing pPediction Gridding Heterogeneity Modelling Inflow Performance Injectivity Productivity Index Material Balance Material Balance Mature Field History Match Mechanism Modelling - Experimental Design Modelling data Multipoint Flux Approximation Naturally Fractured Reservoirs Naturally Fractured Reservoirs Naturally Fractured Reservoirs

LWD Interpretation LWD Interpretation Production Potential maps Real Time Pressure Data Selection Criteria Thin Oil Rim Well Placement Optimisation SAGD Single Layer Multilayered Reservoirs Adjoint Based Simulation Adjoint Based Simulation Artificial Intelligence Experimental Design Method Face Recognition Technique Analytical Heavy Oil Phase-Component Partitioning Thin Oil Rim

3 Phase Model 3 Phase Clean-up Model Fractured Horizontal Wells Gas Condensate Geometry Horizontal Wells Non-Darcy/Perforation Flow Probablistic Productivity Index Transverse Fractures Neural Networks Optimisation Temperation Prediction Complex Mature Reservoirs Uncertainty Management Diffusion and Convection Experience Capillary data Upscaling Dual Porosity Model Applicability Gas Oil Displacement History Matching

Naturally Fractured Reservoirs Naturally Fractured Reservoirs Naturally Fractured Reservoirs Naturally Fractured Reservoirs Numerical - Conceptional Prediction Uncertainty Proxy Modeling Scale Modelling Shared Earth Modelling Steamflood Modelling Streamline Streamline Type Curve Forecasting Uncertainty Management Uncertainty Management Wellbore Flow Wellstream Composition Wellstream Composition Mechanism Mechanism Mechanism Mechanism - Transition zone flow UBD Wellbore Stability Smarter Fields EOR Techniques Province Comparison Well Intervention By-passed Oil Detection By-passed Oil Detection By-passed Oil Detection Complex Wells Complex Wells Complex Wells Condensate Banking Detection Data Acquisition Data Acquisition Downhole Monitoring Downhole PH Measurement Formation Damage Detection Fracture Diagnostics Fracture Diagnostics Gas Entry Detection Inflow Performance Inflow Profiling Inflow Profiling Inflow Profiling Inflow Profiling Multiphase Metering Naturally Fracture Detection Pemanent Downhole Gauge

Multiple Reservoirs Streamlines Streamlines Streamlines Production Optimisation PUNQ-S3 Problem Production Optimisation Streamlines PEBI Grid Adaptive Mesh Refinement Multicomponent Well Placement Ensemble based Application Ranking GeoModels Annuus and Tubing Flow Black-Oil Delumping Black-Oil Delumping Effect of Wettability Fines Migration Non-Dacy Flow Carbonate Reservoirs Margham Field Stress Patterns Change Management Russia UKCS vs Alaska North Slope Zonal Isolation Mature Fields Pulse Neutron Logs Downhole Flowrates Inflow Profiling PLT Multiphase Flowmeters Challenging Conditions Challenging Conditions Multiple Reservoirs Optical Spectroscopy Microseismic Monitoring Temperature Log Analysis SAGD - Horizontal Wells Pulse Neutron Logs Pulse Neutron Logs Temperature Data Tracers Downhole Feasibility

Performance Prediction PLT Interpretation Pressure Monitoring Production Monitoring Real-Time Monitoring Real-Time Monitoring Reservoir Pressure/GOR Monitoring SAGD Monitoring Sand Production Sandface Monitoring Theif Zone Dectection Value of Information Virtual Metering Water Entry Detection Water Entry Detection Water Entry Detection Water Front Tracking Waterflood Waterflood Coal Coalbed Methane Coalbed Methane Completion Strategies Fracture Design Fracture Design Reservoir Description Reservoir Modelling SAG State of the Nation Stimulation Acid Treatments Artificial Lift Artificial Lift Artificial Lift Completion Optimisation Completion Optimisation Completion Optimisation Completion Optimisation Completion Optimisation Completion Optimisation Complex Wells Complex Wells Complex Wells Complex Wells Complex Wells Complex Wells Complex Wells ESP ESP Fracture Design Fracture Design

Assessment Challenging Conditions Greater Burgan Field Temperature Data Case Study WFT Tempreture Data Tiltmeters Temperature Sensors Completion Design Borehole Images Opportunistic/Guaranteed Horizontal wells Horizontal wells Resistivity Measurement LWD Electromagnetic Surveys Electromagnetic Surveys Perforation Testing Completion Optimisation Indirect Fracturing Horizontal Wells Heterogeneity Horizontal Well Characterisation Well Optimisation Petroleum Engineering Advances Refracturing Production Optimisation ESP's SAGD ESP Staircase Lifting Horizontal Wells Manati Gas Filed Multilayered Reservoirs Near Wellbore Stress

Carbonate Reservoir Complex Reservoirs Downhole Control Valves Downhole Control Valves Downhole Control Valves Intervention Production Performance Perforation Methods Performance Analysis Acid Fracturing Candidate selection

Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Design Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics

Fiber Assisted Fiber Assisted Fiber Assisted Fiber Assisted Flowback Aids Formation Modulus Contrast Fracture Fluid Fracture Fluids Optimisation Fracture Geometry Fracture Propagation Height Control Horizontal Well Application Mature Fields Multifrac Horizontal Wells Multistage Multistage Horizontal Wells Multistage Horizontal Wells Multistage Horizontal Wells Optimisation Performance Criteria Proppant Transport Samara Area Reservoirs Simultaneous Fracturing Sliding Sleeve Application Sliding Sleeve Applocation Soft Formations Surfactant Fracturing Surfactant Fracturing Surfactant Fracturing Surfactant Fracturing Acid Fracturing Clean-up Completion Optimisation Damage Analysis Deviation Surveys Fiber Assisted Fracture Conductivity Fracture Geometry Fracture Geometry Fracture Geometry Gas Condensate Gas Condensate High Permeability Formations Long-Term Rate Effects Low-Conductivity Microseismic Monitoring Proppant Flowback Refracture Reseridual Saturation Sonic Anisotropy

Fracture Diagnostics Fracture Diagnostics Fracture Diagnostics Fracture Dignostics Gas Lift Systems Gas Production Horizontal Well Horizontal Well Horizontal Well Intelligent Well Intelligent Well Intelligent Well Intelligent Well Intelligent Well Lab Testing - Fracturing Modelling - Flow Assurance Modelling - Well Productivity Modellling - Sanding Prediction Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Perforation Methods Production Optimisation Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control Sand Control

State of the Nation Water Injector Fracturing Fracture Geometry Theory High rate wells Novel Open hole Novel Open hole OBM Effect Complex Wells Downhole Control Valves ESP's Production Optimisation Uncertainty Management Heterogeneity Productivity Improvement Heterogeneity Carboate Reservoir Case study Coiled Tubing Dynamic UB Negative Skin Factors Orientation Productivity Improvement Skin Variation Quantified UnderBalanced

SMART Completions Albacora Field Completion Optimisation Complex Wells Failure Failure Mitigation Failures Gravel Pack Gravel Pack Gravel Pack Gravel Pack Gravel Pack Gravel Pack Modelling Gravel Packing Optimisation Perforate/Gravel Pack Perforation Method Screen Technology Screenless Completions Screens

Sand Management Sand Production Sand Production Sand Production Sand Production Sand Production Sand Production State of the Nation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Stimulation Optimisation Water Blocking Water Control/Stimulation Zonal Isolation Analysis - Closed Chamber Tests Analysis - Horizontal Wells Analysis - Multi-Fractured Wells Analysis - Multilayer Reservoir Analysis - Naturally Fractured Reservoir Analysis - Radius of Investigation Analysis - Real Time Evaluation Deconvolution Exploration Wells Fracture Diagnostics Mini-DST MiniDST Interpretation Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering Multiphase Metering

Sarir Field Accurate Pediction Case Study Effect of water-Cut Mature Fields Wellbore Stability Wellbore Stability Acid treatment Acid Fracturing Acid Fracturing Acid Fracturing Acid Fracturing Acid treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Acid Treatment Chelating Agent Application Combined Treatments Diversion Techniques Foam Fracturing Heterogeneity Restimulation Surfactant Fracturing Surfactant Fracturing Mature Fields Gas Reservoirs Sufactant Treatment CBL Interpretation Carbonate Reservoir Stacked Reservoirs Layer Properties Partial Penetration Reserve Estimation

Design and Interpretation Image Log Deepwater Gas Challenging Conditions Gas Condensate Heavy Oil Reliability Validation

Multiphase Metering Numerical Modelling Production Analysis State of the Nation Streaming Potential Measurement

Full Field Simulations Integral Derivative Function Advances in Interpretation and Measurement Technology Application

Title Assessing Long-Term CO2 Containment Performance: Cement Evaluation in Otway CRC-1 Stress Estimation at the Otway CO2 Storage Site, Australia CO2 Storage - Managing the Risk Associated With Well Leakage over Long Timescales Optimizing CO2 Injection and Storage: A New Approach Using Integrated Asset Modeling Simulations for CO2 Injection Projects With Compositional Simulator Lithological and Petrophysical Core-Log Interpretation in CO2SINK, the European CO2 Onshore Rese CO2 Sequestration - A Safe Transition Technology CO2 Storage Geomechanics for Performance and Risk Management Critical Issues in CO2 Capture and Storage: Findings of the SPE Advanced Technology Workshop ( Production Data Standards: The PRODML Business Case and Evolution World-Record ERD Well Drilled From a Floating Installation in the North Sea Dumbarton Field, UKCS: Rapid Redevelopment of a Complex, Mature North Sea Asset Using New Ro How Continuous Improvement Lead to the Longest Horizontal Well in the World EOR Potential of the Michigan Silurian Reefs Using CO2 Quebrache--A Natural CO2 Reservoir: A New Source for EOR Projects in Mexico Oligocene Vicksburg Thin-Bed Production Optimization Derived From Oil-Based Mud Imaging: A Ca Simulation Study of Re-Entry Drilling for Gas/Condensate Reservoir Development Applicability and Optimization of SAGD in Eastern Venezuela Reservoirs Challenging Chemical Gas Shut Off In a Fractured Carbonate Reservoir—Case Studies Recovery of Bypassed Reserves Above Top Packer Using Innovative Cement Packer and Through Tu Production Improvement Water Shut-Off for White Tiger Field Case Study in Water Shutoff Fluid Placement Using Straddled Through-Tubing Inflatable-Packers Te Water-Shutoff Treatment in Wells With Single-String Multizone Completion Intervals (Brownfields) Successful Water Shut-off in Open Hole Horizontal Well Using Inflatables Innovative Water-Shutoff Solution Enhances Oil Recovery From a West Venezuela Sandstone Reser Horizontal Water Shut-Off for Better Production Optimization and Reservoir Sweep Efficiency (Case Successful Utilization of Fiber Optic Telemetry Enabled Coiled Tubing for Water Shut-off on a Horizon A Holistic Approach to Production Assurance Characterization of Oil/Water Flows in Horizontal Pipes Characterization of Oil/Water Flows in Inclined Pipes A Rigorous Well Model To Optimize Production From Intelligent Wells and Establish the Back-Allocat Integration of Production and Process Facility Models in a Single Simulation Tool - PEMEX E&P San Impact of Flow Assurance in the Development of a Deepwater Prospect Flow-Assurance Aspects of Subsea Systems Design for Production of Waxy Crude Oils Quantification of Carbon Dioxide Using Downhole Wireline Formation Tester Measurements First Field Application of Downhole CO2 Measurement in Asia Pacific Core Flood Investigation Into Asphaltene Deposition Tendencies in the Marrat Reservoir, South East Tools To Manage Gas/Condensate Reservoirs; Novel Fluid-Property Correlations on the Basis of� New Modified Black-Oil Correlations for Gas Condensate and Volatile Oil Fluids Asphaltene Gravitational Gradient in a Deepwater Reservoir as Determined by Downhole Fluid Analy Reservoir Fluid Characterization Using Downhole Fluid Analysis in Northern Kalimantan, Indonesia Continuous Downhole Fluid Log Powered by an Integrated Approach Reveals Reservoir Fluid Complex Application of Artificial Neural Networks to Downhole Fluid Analysis Compositional Modeling of Oil-Based Mud-Filtrate Cleanup During Wireline Formation Tester Sampli New Downhole Fluid Analysis (DFA) Technologies Supporting Improved Reservoir Management Applying Downhole Fluid Analysis and Wireline-Formation-Testing Techniques in Reservoir Manage Advanced Formation Testing in OBM Using Focused Fluid Sampling for Producibility Evaluation in Ma Low-Level Hydrogen Sulphide Detection Using Wireline Formation Tester

Integration of Fluid Log Predictions and Downhole Fluid Analysis How Reliable Is Fluid Gradient in Gas/Condensate Reservoirs? Integration of Geochemical, Mud-Gas, and Downhole-Fluid Analyses for the Assessment of Composi Fluid Identification Challenges in the Near Critical Fluids: Case Studies in Malaysia Hydrocarbon Compositional Gradient Revealed by In-Situ Optical Spectroscopy Pressure Measurement and Pressure Gradient Analysis: How Reliable For Determining Fluid Density Integration of In-Situ Fluid Measurements for Pressure Gradients Calculations Downhole Measurement of Methane Content and GOR in Formation Fluid Samples Modeling the Effect of Asphaltene on the Development of the Marrat Field EOS-Based Downhole Fluid Characterization Advanced Compositional Gradient Analysis Downhole Fluid Analysis and Fluid-Comparison Algorithm as Aid to Reservoir Characterization Application of Artificial Neural Networks to Downhole Fluid Analysis Enhanced Characterization of Multi-Phase Downhole Fluid Samples Using a Full Spectrum Weighted Practical and Robust Isenthalpic/Isothermal Flashes for Thermal Fluids Rheology of Heavy-Oil Emulsions Reservoir Fluid Analysis Using PVT Express Downhole Fluid Analysis Integrating Insitu Density and Viscosity Measurements - Field Test from In-Situ Density and Viscosity Measured by Wireline Formation Testers Fluid Sampling in Carbonates-Challenges and Best Practices Focused Sampling of Reservoir Fluids Achieves Undetectable Levels of Contamination Wireline Gas-Condensate Sampling: A Unique, Proven Solution An Innovative Multiphase Sampling Solution at the Well Site to Improve Multiphase Flow Measureme Sampling With Multiphase Flowmeter in Northern Siberia—Condensate Field Experience and Sensiti Reaction of Simple Organic Acids and Chelating Agents With Calcite Novel Chelating-Based Technology Application in Complex and Heterogeneous Injector Wells in the A Sandstone Cores as Reaction Vessels: Synthesis of Calcium Carbonate Particles for Artificial Formati Mechanistic Study of Chemicals Providing Improved Halite Inhibition Taking Advantage of Injectivity Decline for Sweep Enhancing during Waterflood with Horizontal Inject Mechanisms, Parameters, and Modeling of Naphthenate-Soap-Induced Formation Damage New Fundamental Insights into Perforation-Induced Formation Damage Perforation Damage Removal by Underbalance Surge Flow First Application of Scale Inhibitor During Hydraulic Fracturing Treatments in Western Siberia Optimization of a Scale Treatment in the Uinta Basin—A Case History Impact of Intelligent Wells on Oilfield Scale Management Techniques Used To Monitor and Remove Strontium Sulfate Scale in UZ Producing Wells Impact of In-Situ Sulfate Stripping on Scale Management in the Gyda Field Optimal Region Delineation in a Reservoir for Efficient History Matching Fracture Lineament Validation using Streamline Simulation in a Giant Middle East Field: An Innovati Streamline Simulation for Reservoir Management of a Super Giant: Sabiriyah Field North Kuwait Ca Managing Water and Gas Production Problems in Cantarell: A Giant Carbonate Reservoir in Gulf of Automatic Surveillance System for Large Gas Fields With Multifrequency Measurements Tracking Interwell Water Saturation in Pattern Flood Pilots in a Giant Gulf Oil field Pattern Balancing and Waterflood Optimization of a Super Giant: Sabiriyah Field, North Kuwait, a C Producing Extra-Heavy Oil from the Orinoco Belt, Cerro Negro Area, Venezuela, Using Bottom-Drive Feasibility of using Electrical Downhole Heaters in Faja Heavy Oil Reservoirs Microwave Assisted Gravity Drainage of Heavy Oils Horizontal Alternating Steam Drive Process for the Orinoco Heavy Oil Belt in Eastern Venezuela Development of Small Size-Heavy-Oil Field With Innovative Technology Characterization of Complex Carbonate Heavy Oil Reservoir—A Case Study A Technique for Measuring Permeability Anisotropy and Recovering PVT Samples in a Heavy Oil Rese

Developing Heavy Oil Field By Well Placement - A Case Study Optimizing Horizontal-Well Steam-Stimulation Strategy for Heavy-Oil Development Smart Chemical Systems for the Stimulation of High-Water-Cut Heavy Oil Wells Horizontal-Well-Production Logging Experience in Heavy-Oil Environment With Sand Screen: A Cas Thermal Simulation and Economic Evaluation of Heavy-Oil Projects Case Study in Venezuela: Performance of Multiphase Meter in Extra Heavy Oil Methodology of Calibration for Nucleonic Multiphase Meter Technology for SAGD Extra Heavy Oil Investigation of a New Single-Stage Sandstone Acidizing Fluid for High-Temperature Formations Formation Testing and PVT Sampling in Low-Permeability, High-Pressure Gas Condensate Reservoir Successful Application of Exploration Lessons Learnt To Deliver Stretch HT/HP Well Delivery Objecti Numerical Investigation of Gravitational Compositional Grading in Hydrocarbon Reservoirs Using Cen A New Shear-Tolerant High-Temperature Fracturing Fluid New Fracturing Fluid for High Temperature Reservoirs Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbon Coiled-Tubing-Conveyed Perforating for High-Pressure/High-Temperature Environment in Mexico Ma First High Pressure and High Temperature Digital Electric Intellitite Welded Permanent Down Hole M Case Study from 12 Successful Years of High Temperature Fracturing in Bach Ho Field Offshore Vie Effective Stimulation of High-Temperature Sandstone Formations in East Venezuela With a New Sa Stimulation of High-Temperature Sandstone Formations From West Africa With Chelating Agent-Base Successful Application of High-Temperature Viscoelastic Surfactant (VES) Fracturing Fluids Under Wettability Alteration for Water-Block Prevention in High-Temperature Gas Wells Laboratory Measurement of pH of Live Waters at High Temperatures and Pressures Recent Developments in the Deposition of Colloidal Asphaltene in Capillary Flow: Experiments and Optimizing Horizontal Completions in the Cleveland Tight Gas Sand Horizontal Well Completion and Stimulation Techniques--A Review With Emphasis on Low-Permeabil The key challenges for Optimization of a Tight Gas Field Developments Using a Multi-Domain Integr Observations From Tight Gas Reservoir Stimulations in the Rocky Mountain Region Reservoir Pressure Depletion and Water Flooding Influencing Hydraulic Fracture Orientation in Low-Pe Characterization of Hydraulically-Induced Fracture Network Using Treatment and Microseismic Data Application of Hybrid Fracture Treatment to Tight Gas Sands in East Texas Cotton Valley Sands Benefits of the Novel Fiber-Laden Low-Viscosity Fluid System in Fracturing Low-Permeability Tight Increasing Reservoir Contact by Combining Mechanical Diversion and Unique Stimulation Chemistry Multiple Transverse Fracturing in Horizontal Open Hole Allows Development of a Low-Permeability R Multiple Proppant Fracturing Treatments Unleashed High Gas Rate From an Openhole Horizontal Tig Horizontal Drilling Application To Recover Incremental Oil in Low-Permeability Carbonate Reservoirs, Well Production Forecast in a Tight Gas Reservoir—Closing the Loop With Model-Based Prediction Uinta Basin Single-Well Model to Optimize Tight Gas Completions Numerical Simulation of Thick, Tight Fluvial Sands Fracturing Previously Bypassed Highly Laminated Tight Gas Sands, A Production Optimization Case A New Formation-Evaluation Technique for the Lower Tertiary in South Texas--Predicting Production Fracture and Sub-Seismic Fault Characterization for Tight Carbonates in Challenging Oil-Based Mu Multidisciplinary Approach and New Technology Improve Carbonate Reservoir Evaluation Applied Natural Fracture Characterization Using Combination of Imagery and Transient Information A Case Study: Using Wireline Pressure Measurements to Improve Reservoir Characterization in Tig A Case Study: Using Wireline Pressure Measurements To Improve Reservoir Characterization in Ti Best Practices for Formation Testing in Low Permeability Reservoirs Field-Development Case Study: Production Optimization Through Continuous Multidisciplinary Reser Horizontal Wells in Tight Gas Sands--A Method for Risk Management To Maximize Success Low Porosity Fractured Reservoir Characterization For Exploration and Horizontal Drilling Data Acquisition and Formation Evaluation Strategies in Anisotropic, Tight Gas Reservoirs of the Su Optimum Logging Programs in Tight Sands

Identification and Characterization of Transition Zones in Tight Carbonates by Downhole Fluid Analys Successful Innovative Water-Shutoff Operations in Low-Permeability Gas Wells Stepping on Development of Small and Medium Size Oilfields through Horizontal Wells—The Way Mini Fracturing: A New Horizon of Breakthrough Integrated Technology for Small Fields Analysis of Multicriteria Decision-Making Methodologies for the Petroleum Industry Judgment Elicitation Process for Decision-Making in the Oil and Gas Industry The Importance of Hole Quality for Effective Image Log Interpretation Clearly Demonstrated in an Ei Application of NMR T2 Relaxation for Drainage Capillary Pressure in Vuggy Carbonate Reservoirs Characterization of Reservoir Heterogeneity Through Fluid Movement Monitoring With Deep Electr Integration of borehole image log enhances conventional electrofacies analysis in dual porosity carbo Reconstructing Sedimentary Depositional Environment With Borehole Imaging and Core: A Case Stu Sedimentary Facies Computation and Stratigraphic Analyses Using Well Logs, Borehole Images and C New Downhole-Fluid-Analysis Tool for Improved Reservoir Characterization Reservoir Fluid Characterization Using Downhole Fluid Analysis in Northern Kalimantan, Indonesia Porosity Partitioning and Flow Unit Characterization From an Integration of Magnetic-Resonance Flow Unit Characterization and Geo-modeling of a Structurally Complex Fluvio-deltaic Reservoir usi A New-Generation LWD Tool With Colocated Sensors Opens New Opportunities for Formation Evalu New Developments in Sourceless Logging-While-Drilling Formation Evaluation: A Case Study From S Why the LWD and Wireline Gamma Ray Measurements May Read Different Values in the Same Wel Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertain Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertain A New Workflow for Comprehensive Petrophysical Characterization of Carbonate Reservoirs Drilled Enhanced Reservoir Description in Carbonate and Clastic Reservoirs Case Study of Permeability, Vug Quantification, and Rock Typing in a Complex Carbonate Applications of NMR Logs and Borehole Images to the Evaluation of Laminated Deepwater Reservoi Integration of Borehole Imaging, Open Hole Logs, Nuclear Magnetic Resonance/Modular Dynamic Tes Evaluation of Low-Resistivity-Pay Deepwater Turbidites Using Constrained Thin-Bed Petrophysical A Formation Evaluation in Thin Sand/Shale Laminations Formation Evaluation of Horizontal Water Injectors Drilled in Thick Carbonate Reservoirs: Behind-C Integration of Production, Pressure Transient and Borehole Images in Horizontal Wells Drilled in C Specialized Techniques for Formation Testing and Fluid Sampling in Unconsolidated Formations in Geomechanics Insight Into Discrepancies of Core to Image Log Discontinuities and Implications for Exploration Potential of Sinuous (Channellike) Events in Late Cretaceous of Al-Khafji Field, Middle E Understanding a Reservoir: 3D Geological Modelling Using Scenario-Based Approach and Conventio Frequentist Meets Spatialist: A Marriage Made in Reservoir Characterization and Modeling Methods for Real-Time and High-Resolution Formation Evaluation and Formation Testing of Thinly Be NMR Petrophysics in Thin Sand/Shale Laminations Successful Application of New LWD Platform Provides Integrated Real-Time Formation Evaluation in Improving LWD Image and Formation Evaluation by Utilizing Dynamically Corrected Drilling-Derive From Issues to Solutions – Introducing the Multi Function Logging While Drilling Tool for Reservoi Stress Reorientation Around Horizontal Wells Prediction of Rock Mechanical Parameters for Hydrocarbon Reservoirs Using Different Artificial Intel Estimation of Near-Wellbore Alteration and Formation Stress Parameters From Borehole Sonic Data Characterization of Multilayer Reservoir Properties Using Production Logs Characterization of Commingled Reservoir Properties With Production Logs Evaluation of Commingled Reservoir Properties Using Production Logs An Approach to Fracture Characterization Using Borehole Seismic Data Integrated Fracture Study using Formation Micro Imager, Stoneley Waves and Formation Evaluation R Continuous Fracture Modeling of a Carbonate Reservoir in West Siberia Characterization of Fractures and Faults From High-Resolution Image Logs To Optimize the Geologi Application of an Integrated Approach for the Characterization of a Naturally Fractured Reservoir i

Determination of In-Situ Two-Phase Flow Properties Through Downhole Fluid Movement Monitoring The Impact of the Downhole Formation Tester with Comprehensive Data Integration in Pre-Khuff Hyd An Investigation of Near-Wellbore Flow Properties Using Sonic Scanner Measurements and Interval Radial Profiling for Completion Effectiveness With New Sonic Measurement in the Gulf of Thailand Porosity With Nuclear Magnetic Resonance in Naturally Fractured Clastics Reservoirs in the Devoni Using the Continuous NMR Fluid Properties Scan to Optimize Sampling with Wireline Formation Test The Application of NMR Logs for the Evaluation of Gas Reservoirs With Low Salinity Formation Wate Porosity Determination From NMR Log Data: The Effects of Acquisition Parameters, Noise, and Inver Advances in NMR Logging Optimization of the Prediction of Hydrocarbon-Producing Zones Through Integration of Petrophysical Comprehensive Reservoir Characterization with Multiphase Production Logging A New Porosity Partitioning-Based Methodology for Permeability and Texture Analysis in Abu Dhabi Simulation of Inflow While Underbalanced Drilling With Automatic Identification of Formation Param Utilizing Real Time Logging While Drilling Resistivity Imaging to Identify Fracture Corridors in a high Combining Continuous Fluid Typing, Wireline Formation Testers, and Geochemical Measurements for Improved Interpretation of Reservoir Architecture and Fluid Contacts Through the Integration of D Predicting Downhole Fluid Analysis Logs to Investigate Reservoir Connectivity Characterization of Reservoir Properties Using Production Logs Remaining Oil Investigation in a High Recovery Oilfield Development and Use of Improved Wireline Formation Tester Technologies in the Challenging Deltai Enhancing Formation Testing and Sampling Operations Through the Use of Log-Derived High-Resolu Direct Measurements of Minimum Horizontal Stress, Permeability, and Permeability Anisotropy in a Si A Method for Analysis of Pressure Response With a Formation Tester Influenced By Supercharging Field Development Plan by Optioneering Process Sensitive to Reservoir and Operational Constraints Reducing Uncertainty Through Downhole Fluid Analysis: A Field Case Study Selection Criteria for Artificial Lift Technique in Bokor Field New Life for a Mature Oil Province via the Integration of Improved Recovery Methods An Integrated Approach to Field Surveillance Improves Efficiency in Gas Lift Optimization in Bokor Fi Differentiating Well Placement Expectations in Saudi Arabia with Production from Stringer Sand Rese Implementing the Optimum Well Placement Strategy for Horizontal Injectors Drilled in Highly Hetero Improved Production in Low-Pressure Gas Wells by Installing Wellsite Compressors An Integrated Computer Based Method to Maximize Infill Drilling, Sidetracking, and Workover Potent Flaring, Gas Injection and Reservoir Management Optimization: Preserving Reservoir Energy Maximi Coupling a Reservoir Simulator With a Network Model to Evaluate the Implementation of Smart Well Integrated Optimization of Field Development, Planning, and Operation A New Approach to Gas Lift Optimization Using an Integrated Asset Model Identifying the Improved-Oil-Recovery Potential for a Depleted Reservoir in the Betty Field, Offshore An Approach for Production Enhancement Opportunities in a Brownfield Redevelopment Plan Energy Balance in Steam Injection Projects Integrating Surface-Reservoir Systems A Successful Process for Embracing Uncertainty and Mitigating Risk - From Geological Understandi Breaking the Barriers-The Integrated Asset Model From Reservoir Through Process, From Today to Tomorrow—The Integrated Asset Model Integration of Production and Process Facility Models in a Single Simulation Tool Integrated Studies on a Conveyor Belt—A New Concept of Study Workflows Based on Stochastic Pr Production Diagnostics and Water Control for the XJG Fields, South China Sea The Integrated Approach to Formation Water Management: From Reservoir Management to Protectio Production Enhancement for Khafji Field Using Advanced Optimization Techniques Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea Transforming Data Into Decisions To Optimize the Recovery of the Saih Rawl Field in Oman A Unique Workflow for Reserves Evaluation in Lower Vicksburg Sands Better Valuation of Future Information Under Uncertainty

Latest Generation Horizontal Well Placement Technology Helps Maximize Production in Deep Water T Brenda Field Development: A Best Practice in Horizontal Well Placement Leading to Optimal Reservo Closing the Loop Between Reservoir Modeling and Well Placement and Positioning Using Real-Time Pressure Data for Well Placement Planning Unlocking the Potential of Mature Fields - An Innovative Filtering and Analysis Approach to Identify Optimizing Horizontal Well Placement and Reservoir Inflow in Thin Oil Rim Improves Recovery and Ex Adjoint-Based Well-Placement Optimization Under Production Constraints A New Analytical Model for the SAGD Production Phase Generalized Analytical Solution for Reservoir Problems With Multiple Wells and Boundary Condition Semi-analytical Solution for Multiple Layer Reservoir Problems with Multiple Vertical, Horizontal, De 3D Field-Scale Automatic History Matching Using Adjoint Sensitivities and Generalized Travel-Time I Fast and Efficient Sensitivity Calculation Using Adjoint Method for 3 Phase Field-Scale History Match Innovative Approach to Assist History Matching Using Artificial Intelligence Experimental Design and Response Surface Models as a Basis for Stochastic History Match—A Nig History Matching Using Face-Recognition Technique Based on Principal Component Analysis Analytical Solutions for the Radial Flow Equation With Constant-Rate and Constant-Pressure Bounda A General Unstructured Grid, Parallel, Fully Implicit Thermal Simulator and Its Application for Large Efficient General Formulation Approach For Modeling Complex Physics Using Production Logs to Calibrate Horizontal Wells in Reservoir Simulation Integrating Advanced Production Logging and Near-Wellbore Modeling in a Maximum- Reservoir-Con Using a Discritized Well Model to Simulate Production Behavior in Horizontal or Multi-Lateral Wells Complex Well Modeling Workflow Enabling Full Field Optimization and Forward Decisions 3D Reservoir Geomechanical Modeling in Oil/Gas Field Production A New Thermal-Compositional Reservoir Simulator with a Novel Equation Line-Up" Method" Effective Use of Production Surveillance Tool in Forecasting Future Production Fracture Impact of Yield Stress and Fracture-Face Damage on Production With a Three-Phase 2D M Numerical Investigation on Hydraulic Fracture Cleanup and Its Impact on the Productivity of a Gas Numerical Modeling of Multiple Hydraulically Fractured Horizontal Wells (MHFHW) New Approach to Simulating Multicomponent Fluids Flow to Hydraulic Fractured Well Hydraulic-Fracture Modeling With Bedding Plane Interfacial Slip Explicit Simulation of Multiple Hydraulic Fractures in Horizontal Wells Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells A Bayesian Production Analysis Technique for Multistage Hydraulically Fractured Wells Design Criteria for Improved Performance of Fractured Wells Modelling of Transverse Hydraulic Fracturing 2D Modeling of Hydraulic Fracture Initiating at a Wellbore With or Without Microannulus The Application of Artificial Neural Networks With Small Data Sets: An Example for Analysis of Fract Incorporation of Static and Dynamic Constraints in Optimum Upscaling: A Field Case Study Unconventional Reservoir Modeling of a Gas Field in the Nile Delta of Egypt Prediction of Temperature Propagation Along a Horizontal Well During Injection Period IPI Method: A Subsurface Approach to Understand and Manage Unfavorable Mobility Waterfloods Material Balance Analysis in Complex Mature Reservoirs - Experience in Samarang Field, Malaysia Pressure and PVT Uncertainty in Material-Balance Calculations History Match of an Old Waterflood: Dealing Wth Decades Worth of Data From Hundreds of Wells Two-Phase Multicomponent Diffusion and Convection for Reservoir Initialization The Pains and Gains of Experimental Design and Response Surface Applications in Reservoir Simula A Systematic Approach to Incorporate Capillary Pressure-Saturation Data Into Reservoir Simulation Multipoint Flux Approximations via Upscaling Why Dual Porosity Models are not Applicable for Simulation of the Near-Wellbore Zone of Gas Conde Simulation of Gas/Oil Displacements in Vuggy and Fractured Reservoirs History Matching of Naturally Fractured Reservoirs Using Elastic Stress Simulation and Probability P

Multiple Reservoir Simulations Integration: An Alternative to Full Field Simulation in the North Kuwai A Three-Phase Compressible Dual-Porosity Model for Streamline Simulation Implicit 1-D Transport Solvers For a Streamline Simulator For Fractured Reservoirs Multiscale Mimetic Solvers for Efficient Streamline Simulation of Fractured Reservoirs Conceptual Models for Fast Tracking Decision Making in the Reservoir Management Quantifying Uncertainty for the PUNQ-S3 Problem in a Bayesian Setting With RML and EnKF Proxy Modeling in Production Optimization The Application of Streamline Reservoir Simulation Calculations to the Management of Oilfield Scale Real Time Integration of Reservoir Modeling and Formation Testing Simulation Study of Steamflooding With Horizontal Producers Using PEBI Grids Acceleration of Streamline Simulation Using Adaptive Mesh Refinement Along Streamlines Thermodynamically Consistent Analytical Approach for Streamline Simulations of Multicomponent H Selection of Infill Drilling Locations Using Customized Type Curves Assessing the Uncertainty in Reservoir Description and Performance Predictions With the Ensemble Ranking of Geostatistical Reservoir Models and Uncertainty Assessment Using Real-Time Pressure Modeling Well Inflow Control With Flow in Both Annulus and Tubing Black-Oil Delumping Techniques Based on Compositional Information from Depletion Processes Black Oil Delumping: Running Black Oil Reservoir Simulations and Getting Compositional Wellstream A Quantitative Model for the Effect of Wettability on the Conductivity of Porous Rocks Fines Migration Evaluation in a Mature Field in Libya Applicability of the Forchheimer Equation for Non-Darcy Flow in Porous Media Understanding the Pressure Gradients Improves Production From Oil/Water Transition Carbonate Z Reservoir Focused Underbalanced Applications in the Margham Field In Situ Stress Pattern and Its Impact in Drilling High- Angle Wells in Gulf of Suez, Egypt Making Our Mature Fields Smarter—An Industrywide Position Paper From the 2005 SPE Forum Current Status of Enhanced Recovery Techniques in the Fields of Russia U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces Zonal Isolation Modeling and Measurements—Past Myths and Today's Realities Practical Steps for Successful Identification and Production of Remaining Hydrocarbons Reserves in The Use of Pulsed Neutron Measurements for Determination of Bypassed Pay: A Multi-Well Study Using the Optimal Through-Casing Measurement to Maximize Oil Recovery: A Case Study From The Permanent Real-Time Downhole Flowrate Measurements in Multilateral Wells Improve Reservoir Moni A Novel Solution to Flow Profiling With an Improved Production-Logging Tool In Short String Section Pushing the Envelope for Production Logging in Extended Reach Horizontal Wells in Chayvo Field, The Identification of Condensate Banking With Multiphase Flowmeters—A Case Study Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate En Improved Techniques for Acquiring Pressure and Fluid Data in a Challenging Offshore Carbonate En An Innovative Multi-Reservoir Permanent Downhole Monitoring System Through A Single Well Real-Time Downhole pH Measurement Using Optical Spectroscopy Surveillance and Diagnostics of Permanent Bottomhole Gauge Data Coupled With Geomechanical Mo New Analytical Techniques To Help Improve Our Understanding of Hydraulically Induced Microseismic “Don't Let the Temperature Log Fool You: False Indications of Height Containment From Case Stu Real Time Diagnostics of Gas Entries and Remedial Shut-off in Barefoot Horizontal Wells Predicting the Flow Distribution on Total E&P Canada's Joslyn Project Horizontal SAGD Producing We Inflow Profiles Obtained With Pulsed Neutron Logs in Subcritical-Velocity Wells Determination of Reservoir Inflow With Pulsed Neutron Logs Under Subcritical Flow Conditions Monitoring Inflow Distribution in Multi-zone, Velocity String Gas Wells Using Slickline Deployed Fib Using Chemical Tracers for Flow Profiling a Subsea Horizontal Well with an Open Hole Gravel Pack Well Surveillance With a Permanent Downhole Multiphase Flowmeter Characterization of Fracture Dynamic Parameters to Simulate Naturally Fractured Reservoirs Permanent Downhole Gauge: A Need or A Luxury?

From Data Monitoring to Performance Monitoring Production Logging Low Flow Rate Wells with High Water Cut Observations from a Fieldwide Pressure Data Acquisition Campaign in the Wara Formation of the Gre A Successful Application of Fiber-Optic-Enabled Coiled Tubing With Distributed Temperature Sensin Real Time Production Monitoring Uncovers Potential for Recovery Optimization, Field Case Study, W The Power of Real-Time Monitoring and Interpretation in Wireline Formation Testing—Case Studies Monitoring Multilayered Reservoir Pressures and Gas/Oil Ratio Changes Over Time Using Permanent Monitoring SAGD Steam Injection Using Microseismicity and Tiltmeters Monitoring Production From Gravel-Packed Sand-Screen Completions on BP’s Azeri Field Wells U Completion Design for Sandface Monitoring of Subsea Wells Detecting Thief Zones in Carbonate Reservoirs by Integrating Borehole Images With Dynamic Meas Real-Time Production--A Virtual Dream or Reality? The Case of Remote Surveillance of ESP and Mu Production Performance Monitoring Workflow A Reduced Risk Alternative for Water Entry Detection in High Water Producing Horizontal Wells Determination of Water-Producing Zones While Underbalanced Drilling Horizontal Wells—Integrati Resistivity Through Casing Measurement Successfully Applied To Improve Oil Recovery And Water S An Innovative Approach in Tracking Injected Water Front in Carbonate Reservoir off Shore Abu Dhab Imaging Injected Water flood Fronts Between Wells in a Complex Carbonate Reservoir: Designing C Constraining Interwell Water Flood Imaging With Geology and Petrophysics: An Example From the M First Laboratory Perforating Tests in Coal Show Lower-Than-Expected Penetration Cleat Characterization in CBM Wells for Completion Optimization Application of Indirect Fracturing for Efficient Stimulation of Coalbed Methane A Field Study in Optimizing Completion Strategies for Fracture Initiation in Barnett Shale Horizontal W Effect of Layered Heterogeneity on Fracture Initiation in Tight Gas Shales Maximizing Energy at Coalface for Coalbed Methane Fracturing Operations Use of Horizontal Well Image Tools to Optimize Barnett Shale Reservoir Exploitation A Workflow for Integrated Barnett Shale Gas Reservoir Modeling and Simulation Effects of Well Placement and Intelligent Completions on SAGD in a Full-Field Thermal-Numerical M Coalbed- and Shale-Gas Reservoirs Barnett Shale Refracture Stimulations Using a Novel Diversion Technique Optimizing Well Productivity by Controlling Acid Dissolution Pattern During Matrix Acidizing of Carbo Case Study: First Successful Offshore ESP Project in Saudi Arabia Pushing the Boundaries of Artificial Lift Applications: SAGD ESP Installations at Suncor Energy, Can Staircase Lifting of Oil Using Venturi Principle: A New Artificial-Lift Technique Selection of an Adequate Completion Type is the Key to Successful Reserves Recovery. Case History of The Challenges and Advantages of Openhole Completions in the Manati Gas Field Multiple-Layer Completions for Efficient Treatment of Multilayer Reservoirs Dipole Radial Profiling and Geomechanics for Near Wellbore Alteration Detection to Improve Producti Production Tubing String Design for Optimum Gas Recovery Optimized Tubing-String Design Modeling for Improved Recovery Application of a Maximum Reservoir Contact (MRC) Well in a Thin, Carbonate Reservoir in Kuwait Succeeding With Multilateral Wells in Complex Channel Sands Using Down-Hole Control Valves to Sustain Oil Production From the First Maximum Reservoir Contact On Reservoir Fluid-Flow Control With Smart Completions Case Study: The Use of Downhole Control Valves to Sustain Oil Production from the First Maximum R Horizontal Open Hole, Dual-Lateral Stimulation, Using a Multilateral Entry with High Jetting Tool Experimental and Numerical Study on Production Performance: Case of Horizontal and Dual-Lateral Development of an Integrated Solution for Perforation, Production and Reservoir Evaluation Survival Analysis: The Statistically Rigorous Method for Analyzing Electrical Submersible Pump Sy Long Term Evaluation of an Innovative Acid System for Fracture Stimulation of Carbonate Reservoirs Horizontal Fracture Stimulation Success in the Alpine Formation, North Slope, Alaska

Fiber-Laden Fracturing Fluid Improves Production in the Bakken Shale Multi-Lateral Play Fiber-Based Fracture Fluid Technology a First for Oil Reservoirs in Western Siberia Field Trials of Fiber Assisted Stimulation in Saudi Arabia: An Innovative Non-Damaging Technique fo Fiber-Laden Fluid: Applied Solution for Addressing Multiple Challenges of Hydraulic Fracturing in We Comparison of Flowback Aids: Understanding Their Capillary Pressure and Wetting Properties Effect of Formation Modulus Contrast on Hydraulic Fracture Height Containment A Faster Cleanup, Produced Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studi Optimizing Fracturing Fluids From Flowback Water Maximizing Effective Fracture Half-Length to Influence Well Spacing Novel Frac-and-Pack Technique for Selective Fracture Propagation A Novel Approach to Fracturing Height Control Enlarges the Candidate Pool in the Ryabchyk Format Application of a Highly Efficient Multistage Stimulation Technique for Horizontal Wells Stimulating High-Water-Cut Wells: Results From Field Applications Efficient Multifractured Horizontal Completions Change the Economic Equation in Latin America Thr Continuous Pumping, Multistage, Hydraulic Fracturing in Kitina Field, Offshore Congo, West Africa Successful Multistage Horizontal Well Fracturing in the Deep Gas Reservoirs of Saudi Arabia: Field Successful Multistage Hydraulic Fracturing Treatments Using a Seawater-Based Polymer-Free Flui Successful Continuous, Multi-Stage, Hydraulic Fracturing Using a Seawater-Based Polymer-Free Flu Optimized Hydrualic Fracturing for the Gandhar Field Production Performance Design Criteria for Hydraulic Fractures Quantifying Proppant Transport for Complex Fractures in Unconventional Formations Particularities of Hydraulic Fracturing in Dome-Type Reservoirs of Samara Area in the Volga-Urals Ba Simultaneous Hydraulic Fracturing of Adjacent Horizontal Wells in the Woodford Shale Novel Technology Replaces Perforating and Improves Efficiency During Multiple Layer Fracturing Op A Study of Fracture Initiation Pressures in Cemented Cased-Hole Wells Without Perforations Semiphenomenological Model of Hydraulic Fracturing in Granular Media Optimization of a Visco-Elastic Surfactant (VES) Fracturing Fluid for Application in High-Permeabilit Novel CO2-Emulsified Viscoelastic Surfactant Fracturing Fluid System Enables Commercial Produc Fracture Stimulation Utilizing a Viscoelastic-Surfactant-Based System in the Morrow Sands in Sout Overcoming Excessive Fluid Loss in Tip-Screen-Out Stimulations of Depleted, High-Permeability Res Fracturing Technology for 4% Porosity Libya’s Reservoir: Application of Correct Diagnostic and An Integrated Evaluation of Successful Acid Fracturing Treatment in a Deep Carbonate Reservoir Ha New Results Improve Fracture Cleanup Characterization and Damage Mitigation Optimizing the Completion of a Multilayer Cotton Valley Sand Using Hydraulic-Fracture Monitoring a Comparative Analysis of Damage Mechanisms in Fractured Gas Wells Borehole Deviation Surveys are Necessary for Hydraulic Fracture Monitoring Evaluation of the Proppant-Pack Permeability in Fiber-Assisted Hydraulic Fracturing Treatments for The Texture of Acidized Fracture Surfaces: Implications for Acid Fracture Conductivity Complex Fracture Geometry Investigations Conducted on Western-Siberian Oilfields at Rosneft Co A New Environmentally Acceptable Technique for Determination of Fracture Height and Width Hydraulic Fracture Geometry Investigation for Successful Optimization of Fracture Modeling and Ove Production Forecasting in a Limited-Data Environment: Evolving the Methodology in the Yamburgsk Correcting Underestimation of Optimal Fracture Length by Modeling Proppant Conductivity Variation Fracture Propagation in High-Permeability Rocks: The Key Influence of Fracture Tip Behavior Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Produc Evaluation and Optimization of Low-Conductivity Fractures Evidence of a Horizontal Hydraulic Fracture From Stress Rotations Across a Thrust Fault Prediction of Long-Term Proppant Flowback in Weak Rocks Effect of Production Induced Stress Field on Refracture Propagation and Pressure Response Hydraulic Fracturing and Filtration in Porous Medium Differential Cased Hole Sonic Anisotropy for Evaluation of Propped Fracture Geometry in Western Si

New Findings in Fracture Cleanup Change Common Industry Perceptions Eliminating the Poroelastic Problems Associated with Water Injection in the Kikeh Deep Water Deve Using Open and Cased Hole Sonic Anisotropy and Geomechanics Modeling for Hydraulic Fracturing E Hydraulic Fracture Offsetting in Naturally Fractured Reservoirs: Quantifying a Long-Recognized Proc Auto, Natural, or In-Situ Gas-Lift Systems Explained A Critical Review of Completion Techniques for High-Rate Gas Wells Offshore Trinidad Application of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia Successful Case History of a Novel Open-Hole Horizontal Well Completion in Saudi Arabia A Case Study of Oil-Based Mud Effect on Horizontal-Well Productivity Slim Intelligent Completions Technology Optimize Production in Maximum Contact, Expandable Line First Applications of Inflow Control Devices (ICD) in Open Hole Horizontal Wells in Block 15, Ecuador Integrating ESPs with Intelligent Completions: Options, Benefits and Risks Intelligent Completions Technology Offers Solutions to Optimize Production and Improve Recovery in Insurance Value of Intelligent Well Technology Against Reservoir Uncertainty Laboratory Hydraulic Fracturing Test on a Rock With Artificial Discontinuities Managing Production in Maturing Assets: Increasing Intervention Success by Combining Production Forecasting the Productivity of Thinly Laminated Sands with a Single Well Predictive Model Geomechanical Characterization of a Sandstone Reservoir in Middle East—Analysis of Sanding Pre Effective Matrix Acidizing in Carbonate Reservoir—Does Perforating Matter? Productivity Increase Using the Combination of Formation Isolation Valve and Dynamic Underbalance Coiled-Tubing Perforation and Zonal Isolation in Harsh Wellbore Conditions Dynamic Underbalanced Perforating Application Increases Productivity in the Mature High-Permeabil Overbalanced Perforating Yields Negative Skins in Layered Reservoir Oriented Perforation in Dual Completion Wells: A Real Case in East Texas New Perforating Technique Improves Well Productivity and Operational Efficiency Quantifying Skin Variation for Underbalanced Perforating Improved Method for Underbalanced Perforating With Coiled Tubing in the South China Sea Modeling Air and Water Perforator Swell for Better Risk Management Novel Perforating Job Design Triples Well Productivity Flow Performance of Perforation Tunnels Created With Shaped Charges Using Reactive Liner Techn Overcoming Near Wellbore Damage Induced Flow Impairment with Improved Perforation Job Design Reduced Water Production and Increased Oil Production Using Smart Completions and MPFM Case Sand Control Completions for the Development of Albacora Leste Field Magnolia Deepwater Experience--Frac Packing Long, Perforated Intervals in Unconsolidated Silt Res TAML Level 3 tri-lateral with Sand Control application for Saudi Aramco Lessons Learned on Sand-Control Failure and Subsequent Workover at Magnolia Deepwater Devel Novel Through Tubing Sand Control Solution for Failed Gravel Pack - Alpha Well - 4L Case Study Sand Control Completion Failures: Can We Talk the Same Language? A Step Change in Openhole Gravelpacking Methodology: Drilling-Fluid Design and Filter-Cake Rem Greater Plutonio Openhole Gravel-Pack Completions: Fluid Design and Field Applications Complex Through-Tubing Gravel-Pack Operation Increases Production on a Well in the Heidrun Fiel Openhole Gravel Packing With Exposed Shales: Waterpack Case Histories From Underground Gas St Gravel Packing Long Openhole Intervals With Viscous Fluids Utilizing High Gravel Concentrations: T Integrated Approach to Modeling Gravel Packs in Horizontal Wells Openhole Gravel Packing With Oil-Based Fluids: Implementation of the Lessons Learned From Past Effective Perforating and Gravel Placement: Key to Low Skin, Sand Free Production in Gravel Packs Effective Perforating and Gravel Placement: Key to Low Skin, Sand-Free Production in Gravel Packs Determination of Optimum Perforation Design and Sanding Propensity in Long Horizontal Wells Bas ICD Screen Technology in Stag Field to Control Sand and Increase Recovery by Avoiding Wormhole Screenless Completions as a Viable Through-Tubing Sand Control Completion The Search for Alternative to Screen: Is Permeable Cement a Viable Option?

Case Study: The Application of a Sand Management Solution for the Sarir Field in Libya Practical Approach to Achieve Accuracy in Sanding Prediction Sanding—Not As It First Appeared Effect of Water Cut on Sand Production—An Experimental Study Bokor--A New Look at Sand Production in a Mature Field Influence of Rock Failure Characteristics on Sanding Behavior: Analysis of Reservoir Sandstones An Integrated Wellbore Stability and Sand-Production Prediction Study for a Multifield Gas Develop Lessons Learned From Using Viscoelastic Surfactants in Well Stimulation Small-Scale Fracture Conductivity Created by Modern Acid-Fracture Fluids Recent Acid-Fracturing Practices on Strawn Formation in Terrell County, Texas Field Trial of a New Non-Damaging Degradable Fiber-Diverting Agent Achieved Full Zonal Coverage d Successful Application of Innovative Fiber-Diverting Technology Achieved Effective Diversion in Ac Use of Novel Acid System Improves Zonal Coverage of Stimulation Treatments in Tengiz Field Optimization of Acid Stimulation for a Loosely Consolidated Brazilian Carbonate Formation--Multidi A Novel Stimulation Technique for Horizontal Openhole Wells in Carbonate Reservoirs--A Case Study Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Proce Development and Field Application of a New Hydrogen Sulfide Scavenger for Acidizing Sour-Water In Successful Stimulation of Thick, Naturally-Fractured Carbonates Pay Zones in Kazakhstan Matrix Acidizing of Carbonate Reservoirs Using Organic Acids and Mixture of HCl and Organic Acids An Innovative Acid Stimulation Technique for Reviving Dead Wells in the Ghawar Field of Saudi Arabi An Alternative Solution to Sandstone Acidizing Using a Nonacid Based Fluid System With Fines-Migr Combining Acid- and Hydraulic-Fracturing Technologies Is the Key to Successfully Stimulating the Or Chemical Diversion Techniques Used for Carbonate Matrix Acidizing: An Overview and Case Historie Foam Fracturing: New Stimulation Edge in Western Siberia The Effect of Pore-Scale Heterogeneities on Carbonate Stimulation Treatments Restimulation: Candidate Selection Methodologies and Treatment Optimization Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the New Viscoelastic Surfactant Fracturing Fluids Now Compatible With CO2 Drastically Improve Gas Pr Optimized Stimulation Solutions for a Mature Field in Kazakhstan Preventive Treatment for Enhancing Water Removal from Gas Reservoirs by Wettability Alteration High-Water-Cut Wells Stimulation Combined Viscoelastic Surfactant Reliability of Cement Bond Log Interpretations Compared to Physical Communication Tests Between A New Approach for Interpreting Pressure Data To Estimate Key Reservoir Parameters From Closed Challenges Encountered During a Comprehensive Test Analysis for a Horizontal Well in a Thin, Carbo A Unique Methodology for Evaluation of Multi-Fractured Wells in Stacked-Pay Reservoirs Using Com Identifying Layer Permeabilities and Skin Using a Multi-Layer Transient Testing Approach in a Comp Pressure Transient Analysis of Partially Penetrating Wells in a Naturally Fractured Reservoir Radius of Investigation for Reserve Estimation From Pressure Transient Well Tests Real-Time Evaluation of Pressure Transients: Advances in Dynamic Reservoir Monitoring An Investigation of Recent Deconvolution Methods for Well-Test Data Analysis Advanced Methods to Design and Interpret Exploration Well Tests---Two Case Studies Estimating Fracture Permeability and Shape Factor by Use of Image Log Data in Welltest Analysis Mini-DST Applications for Shell Deepwater Malaysia A New Method for Gas Well Deliverability Potential Estimation Using MiniDST and Single Well Mode Extending the Range of Multiphase Metering to Challenging High Water Cut Gas-Lifted Wells: TOTAL Testing Gas Condensate Wells in Northern Siberia With Multiphase Flowmeters Improving Reservoir Characterization Using Accurate Flow-Rate History Reliability of Multiphase Flowmeters and Test Separators at High Water Cut Field Validation Processes for Multiphase Wet Gas Surface Well Testing Solutions: Example From t High-Accuracy Wet-Gas Multiphase Well Testing and Production Metering Production Well Testing Optimization Using Multiphase Flow Meters (MPFM)

Field Experience in Multiphase Gas-Well Testing: The Benefit of the Combination of Venturi and G Linking Well-Test Interpretations to Full Field Simulations Application of the β-Integral Derivative Function to Production Analysis A Digital Pressure Derivative Technique for Pressure Transient Well Testing and Reservoir Characteri Streaming Potential Applications in Oil Fields

Author

Abstract

Matteo Loizzo, SPE, Schlumberger Carbon Services and Sandeep Sharma, Abstract CO2 geological storage is about pumping T. B�rard, B. K. Sinha, SPE, Schlumberger; P. van Ruth, T. Dance, Coo Abstract We present an estimation of the full stre Y. Le Guen, J. Le Gouevec, R. Chammas, B. Gerard, and O. Poupard, Oxa Abstract One of the major challenges associated w A. Primera, W. Sifuentes, and N. Rodr�guez; SPE, Schlumberger Abstract The reduction of greenhouse gas emissi S. Hurter, SPE, D. Labregere, and J. Berge, Schlumberger Carbon ServicesAbstract The need for CO2 emissions reduction a B. Norden and A. F�rster, GFZ German Research Centre for Geosciences, Abstract The storage of carbon dioxide (CO2) in s M. Sengul, Schlumberger Carbon Services Abstract Fossil fuel fired plants are responsible fo T. B�rard, L. Jammes, B. Lecampion, SPE, C. Vivalda, and J. Desroche Abstract Controlling the trapping of CO2 in the su S. Imbus, Chevron Energy Technology Co.; F.M. Orr, Stanford U.; V.A. Kuu Abstract Carbon dioxide capture and storage (CC Dave Shipley, Chevron; Ben Weltevrede, Shell International E&P B.V.; Ala Abstract PRODML™ is a set of production data A. Hjelle, SPE, T.G. Teige, SPE, K. Rolfsen, K.J. Hanken, SPE, and S. Hern Abstract The well 34/8-A-6 AHT2 was drilled from Ukpe John, SPE, Schlumberger; Ian Tribe, SPE, Schlumberger; Jim MansonAbstract The Dumbarton Field operated by Maer Kumud Sonowal and Bjarne Bennetzen, Maersk Oil Qatar AS; Patrick Won Abstract Maersk Oil Qatar AS (MOQ) completed d Brian Toelle and Larry Pekot, Schlumberger Data & Consulting Services, a Abstract The Guelph Formation historically know Heron Gachuz Muro, Sergio Berumen Campos, and Luis O. Alcazar Cancin Abstract CO2 injection is one of the most efficient D.L. Fairhurst, B.W. Reynolds, S. Indriati, and M.D. Morris, SPE, Schlum Abstract The Oligocene Vicksburg formation in S S. Luo, SPE, Schlumberger, and M.A. Barrufet, SPE, Texas A&M U. Abstract Gas-condensate reservoirs usually exhi Jos� Antonio Pi�a R., Jos� Luis Bashbush, Edgar Alexander Ferna Abstract The work presented in this paper describ Hamed Al-Sharji, Ali Ehtesham, Bela Kosztin, and Clement Edwards, PDO; Abstract This paper discusses the gas shut-off tre Wong Chun Seng and Suhaila Wahib, Petronas Carigali; Choo Der Jiun an Abstract West Lutong is a mature field with 8 roun Keng Seng Chan, Schlumberger Well Services; Duong Danh Lam and Aleksey Abstract Oil production from some of wells in the W Redha Kelkouli, SPE, and Maen Razouqi, SPE, Schlumberger, and Saeed AlAbstract Most of the wells in Sabriya Field (Northe Victor E. Uadiale, Schlumberger; Otaru G.Oghie, Shell E&P, U.K.; and Vinc Abstract Due to the stacked nature of reservoirs in Faisal F. Al-Shahrani, Zulfiqar A. Baluch, Nashi M. Al-Otaibi, Saudi Aramco Abstract Water shut-off treatment (WSOT) using Goran Andersson, SPE, PetroBoscan; Gregg Molesworth, SPE, Chevron TecAbstract With the discovery of new fields becomin Alaa A. Dashash, Ibrahim Al-Arnaout, Saad M. Al-Driweesh, Saudi Aramco; Abstract Water production is a major problem for Ahmed Al-Zain, Jorge Duarte, Surajit Haldar, Saad Driweesh, Ahmed Al-J Abstract Water control is the key to prolong well li D. Gonzalez and A. Jamaluddin, Schlumberger Abstract Due to the large potential reserves incre M. Vielma, SPE, Schlumberger; S. Atmaca, SPE, C. Sarica, SPE, and H. Zha Summary The dynamic characteristics of oil/wate S. Atmaca, SPE, C. Sarica, SPE, H.-Q. Zhang, SPE, and A.S. Al-Sarkhi, UnivSummary Oil/water flow is a common occurrence T. Graf, SPE, S.P. Graf, SPE, P. Evbomoen, SPE, and C. Umadia, SPE, S Abstract The installation of intelligent wells to imp Fernando L. Morales/Schlumberger; Juan Cruz Vel�zquez/Schlumberge Abstract Traditionally in the upstream business op Doris L. Gonzalez and Abul K.M. Jamaluddin, Schlumberger; Trond SolbakkeAbstract In deepwater production systems extrem H. Alboudwarej, SPE, Schlumberger; Z. Huo, SPE, Shell Global Solutions (UAbstract Development of deep offshore fields is c N. M�ller, Schlumberger Oilfield Services; H. Elshahawi, Shell Intl. E&P Abstract Carbon dioxide (CO2) occurrence in hyd Saifon Daungkaew, SPE, Jack Harfoushian, SPE, and Boon Cheong, SPE Sch Abstract The inherent uncertainty in establishing r N.H.G. Rahmani, SPE, J. Gao, SPE, and M.N. Ibrahim, SPE, Schlumberger;Abstract Asphaltene precipitation can have profou Adriana P. Ovalle, M-I Swaco; Chris P. Lenn, Schlumberger; and William D. Summary Certain fluid properties are required for A.H. El-Banbi, Schlumberger, and K.A. Fattah and M.H. Sayyouh, Cairo U. Abstract Several authors have shown the applica Oliver C. Mullins and Soraya S. Betancourt, Schlumberger-Doll Research; Abstract The fluids in large reservoirs can be in e Andry Halim, Pertamina, and Nicolas Orban, Elin Haryanto, and Cosan Aya Abstract Fluid identification is an important objecti Moyosore Okuyig and Ahmed Berrim, ADMA-OPCO, and ChengGang Xian Abstract Fluid characterization quantifies the rese Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger; and Nikos Varot Summary Reservoir characterization and asset m F.O. Alpak, SPE, H. Elshahawi, SPE, and M. Hashem, SPE, Shell Intl. E&P, Abstract Miscible oil-based mud (OBM) filtrate co Jes�s A. Ca�as, Evie Freitas, A. Ballard Andrews, Oliver C. Mullins, a Abstract This paper describes a new Downhole Fl M. Khalil and K.K. Maamari, SPE, Petroleum Development Oman, and R.R. Abstract The Gharif anCase Studies T. Beaiji, Saudi Aramco; M. Zeybek, Schlumberger; A. Crowell, R. Akkurt, a Abstract Wireline formation testing provides form Mohamed Hashem and Hani Elshahaw, Shell; Ryan Parasram, Peter Weinhe Abstract Many development projects will rely on p

Julian Y. Zuo, SPE, Oliver C. Mullins, SPE, Chengli Dong, SPE, Dan Zhan Abstract Reservoir fluids frequently reveal comple C.S. Kabir, SPE, Chevron ETC and J.J. Pop, SPE, Schlumberger Summary Collection and analysis of gas/condens Hani Elshahawi, SPE, Shell; Melton Hows, SPE, Chengli Dong, SPE, Lali Abstract Identifying compartmentalization quantify Ko Ko Kyi and�Norfadilah Yahaya, PETRONAS Carigali; Saifon DaungkaAbstract Reservoir fluid identification plays a cruc Go Fujisawa, SPE, Soraya S. Betancourt, SPE, Oliver C. Mullins, Torleif T Summary This paper presents a case study of a N R.R. Jackson, A. Carnegie, and F.X. Dubost, SPE, Schlumberger Abstract Pressure-depth plots have been used fo F.X. Dubost, A.J. Carnegie, O.C. Mullins, M.O. Keefe, S. Betancourt, and J Abstract Reservoir fluids often show complex com Chengli Dong, SPE, Peter S. Hegeman, SPE, and Andrew Carnegie, SPE, SSummary Formation fluid sampling early in the lif T. Yi, A. Fadili, M. Ibrahim, SPE, Schlumberger; B.S. Al-Matar, SPE, Kuwai Abstract This paper describes the study of the effe Julian Y. Zuo, SPE, Dan Zhang, Francois Dubost, SPE, Chengli Dong, SPE Abstract Downhole fluid analysis (DFA) together w Jes�s Ca�as, SPE, Julian Pop, SPE, Francois Dubost, SPE, Schlumber Abstract Steep gradients are common in gas cond Lalitha Venkataramanan, SPE, Schlumberger; Hani Elshahawi, SPE, DanielSummary In recent years formation-sampling an Peter Hegeman, SPE, and Chengli Dong, SPE, Schlumberger, and Nikos Varot Abstract Reservoir characterization and asset man R.J. Butsch, SPE, C.W. Morris, SPE, and K.T. Pinto, SPE, Schlumberger Abstract Formation testers are commonly used to Terry W. Stone, Schlumberger, and James S. Nolen, Consultant Abstract This paper describes in detail computatio Hussein Alboudwarej, Moin Muhammad, and Ardi Shahraki, Schlumberger; She Summary Water is invariably produced with crude I.A. Khan, K. McAndrews, J.P. Jose, and A.K.M. Jamaluddin, Schlumberger, Abstract Representative reservoir fluid sampling & Mosleh Khalil, Huda Rumhi, SPE, Petroleum Development Oman, Mahaly Ran Abstract The new generation of wireline formation Michael O'Keefe, SPE, Sophie Godefroy, Ricardo Vasques, Anne Agenes, SAbstract A downhole density-viscosity (D-V) sens Ahmed Dawoud, ADCO, John Zaggas, SPE, Schlumberger, and Sammy HaAbstract A heterogeneous carbonate reservoir can Michael O’Keefe, SPE, Schlumberger; K�re Otto Eriksen, SPE, and St Summary A new generation of sampling technolo A. Paul, SPE, Schlumberger Abstract Wireline pressure testers and reservoir f F. Hollaender, SPE, J.J. Zhang, B. Pinguet, SPE, V. Bastos, SPE, E. Delva Abstract Representative reservoir fluid sampling a Vitaliy Afanasyev, Bertrand Theuveny, SPE, Sylvain Jayawardane, Alexand Abstract Multiphase well testing has been acknow L. Li, SPE, and H.A. Nasr-El-Din, SPE, Texas A&M University, and F.F. Cha Abstract Acid stimulation of deep wells is a difficul Martin Urraca, SPE, Schlumberger, and Ferenc Udvari, MOL Abstract The geologically complex Algyo field disc Michael J. Fuller, Schlumberger Abstract Generally matrix acidizing fluids for sand Hua Guan, SPE, M-I SWACO Production Technologies; Richard Keatch, OMS Abstract This paper investigates the application of Bedrikovetsky, P. and Muhammad A. W., U of Adelaide; Chang G., SchlumbeAbstract Injectivity formation damage with waterflo S. Sarac, SPE, F. Civan, SPE, The University of Oklahoma Summary Naphthenate-soap deposition and the r Juliane Heiland, Brenden Grove, Jeremy Harvey, Ian Walton and Andrew MaAbstract Shaped charge perforating subjects the f P. Bolchover, Schlumberger Cambridge Research, and I.C. Walton, SPE, Abstract In cased completions perforations prov K. Cheremisov, SPE, D. Oussoltsev, SPE, and K.K. Butula, SPE, SchlumberAbstract Problems related to inorganic scale preci Leonardo Maschio, Bilu Cherian, Bernhard Lungwitz, Michael Tyndall, and Abstract The precipitation and accumulation of sca V. Kavle, S. Elmsallati, E. Mackay, and D. Davies, Heriot-Watt U. Abstract The main challenge facing the oil indust Jamal Al-Ashhab and Hassouneh Al-Matar, ZADCO, and Shahril Mokhtar, S Abstract Scale deposition in completion strings is E. Mackay, K. Sorbie, and V. Kavle, Heriot-Watt U.; E. S�rhaug and K. MeAbstract While barium stripping is commonly obs S. Yadav, Marathon Oil Company; R. Heim, Schlumberger; S. Bryant, UT AuAbstract In a large field history matching is genera Abdullah A. Al-Najem, Jamil S. Al-Thuwaini, and Abdulatif Al-Omair, Saudi Abstract With the advancement in streamline sim Ibrahim, Muhammad N., SPE, Schlumberger Oilfield Services; Clark, RobertAbstract This paper discusses the incorporation o T.S. Daltaban, Schlumberger Consultant, and A. Miguel Lozada, P. Antonio Abstract Located in the Gulf of Mexico Cantarell F M. Mota, SPE, O.M. Campos, SPE, H. Escalona, and L.D. Teran, Schlumbe Abstract This paper presents the results of an aut Zahid Bhatti, SPE, Yousof Al Mansoori, PSE, Saber El Sembawy, Volker Va Abstract Peripheral water flooding has been the p Clark, Robert A. Jr., SPE, BP; Lantz, James, AAPG, BP; Karami, Hossein, Abstract This paper outlines the successful integra M.A. Ramos and J.C. Brown, Petr�leos de Venezuela S.A.; M. Rojas, O. Summary The traditional means of artificial lift pro Ra�l Rodr�guez, Jos� Luis Bashbush and Adafel Rinc�n, SPE, S Abstract The Orinoco Belt (Faja) in Venezuela con Berna Hascakir, METU; Cagdas Acar, Schlumberger; Birol Demiral, UTP; a Abstract Conventional EOR methods like steam-i Edgar A. Fernandez R. and Jos� Luis Bashbush, Schlumberger Abstract The Orinoco Heavy Oil Belt (Faja) has be Raj Deo Tewari and Mirghani Malik, GNPOC; Mohamed Ahmed Hassan IdrisAbstract Exploration and development of Heavy o Afzal Iqbal, John Smith, Ali Reza Zahedi, Deemer Arthur, and Falah M. Al Abstract The Paleocene/Eocene age 1st Eocene R Achourov V., SPE, Schlumberger, and Khamitov I. and Yatsenko V., SPE, R Abstract Wireline formation testers provide the m

Pan You li, Luo Hui Hong, and Abdel Mageed Sharara, CNPCIS, and Siva Abstract Fula is a heavy oil field located in Muglad Shanqiang Luo, SPE, and Andy Baker, SPE, Schlumberger Abstract T Oil Development Mohamed Ahmed Samir and Islam Elnashar, Scimitar, and Mathew Samue Abstract The Nukhul formation in the Gulf of Suez Ricardo U. Oosthuizen, Ahmed Al Naqi, and Khalaf Al-Anzi, Kuwait Oil Co. Abstract B Oil Environment With Sand Screen: A E.R. Rangel-German, SPE, Natl. Autonomous U. of Mexico and Secretary o � Abstract Many recent hydrocarbon discoveri Ana Marin, PDVSA, Onerazan Bornia, and Bruno Pinguet, Schlumberger Abstract The objective is to present accurately the Bruno PINGUET, Philippe PECHARD, Elsie GUERRA - SCHLUMBERGER, Abstract: Metering of bitumen produced by Steam H.A. Nasr-El-Din, M. Al-Anazi, and A. Al-Zahrani, Saudi Aramco, and Math Abstract Sandstone acidizing is very challenging b Vladislav Achourov, SPE, Schlumberger; German I. Kaledin, SPE, AchimgazAbstract Formation and fluids evaluation of hetero Suresh Kumar, Gujarat State Petroleum Co., and Sami Affes, IPM Schlumb Abstract Much work has already been undertaken P.D. Ting, SPE, and B. Dindoruk, SPE, Shell International E&P Inc., and J. Abstract Fluid properties descriptions are required Mike Parris, Andrey Mirakyan, Carlos Abad, Yiyan Chen, and Fred Mueller, Abstract The extent of crosslinking a polymeric fra C. Abad, A. Mirakyan, M. Parris, Y. Chen, and F. Mueller, Schlumberger Abstract The extent of crosslinking a polymeric fra H.A. Nasr-El-Din and A. Al-Zahrani, Saudi Aramco, and J. Still, T. Lesko, a Abstract Acid fracturing is the commonly applied s Nestor Molero, Sergio Garcia, and Eduardo Zavala, Schlumberger, and Javi Abstract In Pressure/HTemperature Environment Muhammad Shafiq, SPE, Schlumberger; Omar Al-Faraj, Adnan A. Al-KanaanAbstract This paper describes an innovative and r S. Jain, A. Prestridge, P. Dellorusso, and N.C. Nghi, Schlumberger, and D. Abstract This paper presents the results of proppe S.A. Ali, SPE, and C.W. Pardo, SPE, Chevron Energy Technology Co., and ZAbstract The wells in an oil field in East Venezue S. Ali, SPE, E. Ermel, SPE, and J. Clarke, SPE, Chevron; M.J. Fuller, SPE Summary Fluids based on chelating agents have Cristian Fontana and Enrique Muruaga, Tecpetrol S.A., and Daniel Perez, Abstract The San Jorge Basin is characterized by M.K.R. Panga and Y.S. Ooi, Schlumberger Well Services; P.L. Koh, U. Tekn Abstract This paper presents the development of S.G. Mathews and B. Raghuraman, Schlumberger; D.W. Rosiere and W. Wei Abstract This paper describes a new technique fo Alexander D. Wilson, SPE, Edo S. Boek, SPE, Hemant K. Ladva, SPE, and Abstract The aggregation and deposition of aspha M.L. Samuelson, SPE, T. Akinwande, SPE, and R. Connell, SPE, Schlumberg Abstract This paper describes an efficient multista Valdo Ferreira Rodrigues and Luis Fernando Neumann, Petroleo Brasileiro Abstract ThPermeability Carbonates Ahmed Aly, American University in Cairo-Schlumberger and Lee Ramsey, S Abstract As gas demand rises and operators turn Erik Borchardt, Schlumberger; Jessica Cavens and Craig Wieland, EnCana Introduction Unconventional tight gas reservoirs a S. Kuzmina, SPE, Rosneft, K.K. Butula, SPE, Schlumberger and A. Nikitin, Abstract Hydraulic fracture azimuthal orientation d Wenyue Xu, Jo�l Le Calvez, Marc Thiercelin, Schlumberger Abstract Large amount of gas are being produced Abu M. Sani, Sergey V. Nadezhdin, Ruben Villarreal, Thierry Chabernaud, Abstract Hydraulic fracture treatments are necess M. Bulova, SPE, K. Nosova, SPE, D. Willberg, SPE, and J. Lassek, SPE, S � AbstraPermeability Tight Gas Formations Christian P. Veillette and Jerome J. Cuzella, Enduring Resources, and Fre Abstract The Edwards Limestone in South Texas Alberto Casero, SPE, ENI US; Loris Tealdi, SPE, ENI Congo; Roberto Luis Abstract During the past decade multiple transve Khay Kok Lee, SPE, Schlumberger, and�Chunchun Xu, SPE, Gang Chen,Abstract Guang'an gas field in Sichuan Province Thanh Tran, CACT, China; David Barge, Saudi Arabian Texaco; and Stan In Abstract The Ratawi Oolite carbonate reservoir in F.O. Iwere, SPE, H. Gao, SPE, and B. Luneau, Schlumberger Abstract This paper presents a closed-loop reserv B. Cherian, SPE, A. Aly, SPE, S. Denoo, SPE, L. Maschio, SPE, and D. So Abstract In this paper we will present an integrate F.O. Iwere and J.E. Moreno, Schlumberger, and O.G. Apaydin, EOG Resou Summary This paper presents several workflows D.L. Fairhurst, SPE, Schlumberger; M.E. Semmelbeck, SPE, Escondido Reso Abstract Highly laminated tight gas sand sequenc John C. Rasmus, SPE, John P. Horkowitz, SPE, Thierry Chabernaud, SPE, Summary Th Predicting Permeabilit Bingjian Li, Schlumberger; Mishari Al-Awadi, Kuwait Oil Company;�Ch Abstract Evaluating natural fractures in tight carbo Moyosore Okuyiga, Ahmed Berrim, Ragab Shehab, ADMA-OPCO; Sammy Ha Abstract Wireline formation testing in low permeab Noureddine Bounoua, Sonatrach DP, and George Dozier, Philippe MontaggioAbstract A majority of the world’s oil and gas r R. A. Schrooten, BP America; E.C. Boratko, H. Singh, D.L. Hallford, Schlu Abstract Improving recovery in tight gas reservoirs R.A. Schrooten, BP America; E.C. Boratko, H. Singh, and D.L. Hallford, S Abstract Improving recovery in tight gas reservoirs Peter Weinheber and Edward Boratko, Schlumberger; Kilamba Diogo ContreAbstract The data provided by wireline formation t Hector Ruiz, SPE and Phil Poettmann, SPE, Schlumberger; Tatiana KryuchkSummary This paper presents a field-developmen Jason Baihly, Dee Grant, Li Fan, and Suhas Bodwadkar, Schlumberger Summary In general successful applications of h E. Sokolov, JSC Russneft, and G. Makarytchev and E. Troitskaya, Schlumb Abstract Yurubcheno-Takhomskaya oil and gas a H.J. de Koningh, SPE, and S.H. Al-Mahrooqi, SPE, Petroleum Developmen Abstract In a time of declining production and incr M.Tchambaz, SPE, Schlumberger Abstract High potential of tight sands (quartzitic sa

Chenggang Xian, Schlumberger; Ahmed Dawoud, ADCO; Andrew Carnegie,Abstract S In tight carbonate reservoirs several fact Hassan Chaabouni, SPE, Philippe Enkababian, SPE, and Keng Seng Chan,Abstract S Water production from gas producing we R.D. Tewari, SPE, and M. Malik, SPE, GNPOC, and S. Naganathan, SPE, Abstract Maximization of recovery from anisotrop C.H. Sia, SPE, Azhar M. Ali, SPE, and N. Ezalina Hamzah, SPE, PETRONAS Abstract This paper presents a case history of a s Lev Virine SPE, and Derek Murphy SPE, Schlumberger Ltd. Abstract Decision-making within the petroleum ind Lev Virine, SPE, Schlumberger Abstract Decision-making related to oil and gas e Saud Jumah, Khaled Saleh, and Haitham I. Al-Mayyan, Kuwait Oil Co., and Mi Abstract The objective of supplying real time LWD J. Ouzzane, M. Okuyiga, N. Gomaa, Adma Opco; R. Ramamoorthy, D. Rose,Abstract Capillary pressure curves are a fundame Lang Zhan, SPE, and Fikri Kuchuk, SPE, Schlumberger; S. Mark Ma, SPE, Abstract Cores open hole logs formation testers Christian Perrin/Schlumberger, Mohamad Rafiq Wani/KGOC, Mahmood Akba Abstract Electrofacies based on conventional logs Chandramani Shrivastva and Sanchita Ganguly, Schlumberger, and Zuber Abstract Establishing the depositional sedimentar Taofeek Ogunyemi, Philippe Montaggioni, SPE, and Ibtissam Boubakeur, ScAbstract The Triassic reservoirs of the eastern Sa C. Dong, SPE, and M. O'Keefe, SPE, Schlumberger; H. Elshahawi, SPE, and Summary Downhole fluid analysis (DFA) has eme Andry Halim, Pertamina, and Nicolas Orban, Elin Haryanto, and Cosan Aya Abstract Fluid identification is an important object Aditi Pal, Kapil Seth, and Udit Guru, Schlumberger, and R.R. Tiwari and D Abstract The petrophysical evaluation of carbona Varun Sharma, Sagnik Dasgupta, Arathi. L. Mahesh, and Sachin Sharma, Schl Abstract The Lower Tipam sandstone reservoir of Thomas J. Neville, SPE, Schlumberger; Geoff Weller, SPE, and Ollivier F Summary A new logging-while-drilling (LWD) tool E. Mirto, SPE, G. Weller, SPE, T. el-Halawani, SPE, J. Grau, SPE, M. Berheid Abstract Radioactive chemical logging sources h A. Mendoza, SPE, U. of Texas at Austin; D.V. Ellis, Schlumberger DollAbstract Many concerns have been expressed re Samiha S. El-Sayed, SPE, and Ahmed M. Daoud, Schlumberger, and El-Saye Abstract Quantifying the uncertainty in the volume Samiha S. El-Sayed, SPE, Cairo University Abstract � Quantifying the uncertainty in the vo Asbjorn Gyllensten, Mohamed Ibrahim Al-Hammadi, Emhemed Abousrafa, AAbstract One of the top concerns for carbonate re Zohreh Movahed, Shahid Beheshti University Abstract The reservoir is composed of a mixture o N. Gomaa, A. Al-Alyak, D. Ouzzane, O. Saif, and M. Okuyiga, ADMA OPCO,Abstract This case study demonstrates a new me Michel Claverie, Steve Hansen, Saifon Daungkaew, and Zane Prickett, Schl Abstract Deepwater turbidite reservoirs are comp A.M. Daoud, SPE, M. Eisa, SPE, R. El-Mahdy, SPE, and M. Emam, SchlumbAbstract Specifying the perforation intervals and e R. Bastia, A. Tyagi, and K. Saxena, Reliance Industries Ltd. and T. Klimen Abstract Bed Petrophysical Analysis Chanh Cao Minh and Isabel Joao, Schlumberger, and Jean-Baptiste Cla Abstract Formation evaluation in thin sand-shale l S.M. Ma and A.A. Al-Hajari, Saudi Aramco, and P. Butt and S. Crary, Schlu ABSTRACT Formation evaluation (FE) of horizon Taofeek Ogunyemi, Philippe Montaggioni, SPE, Atmane Azzougen, SPE, andAbstract The economical viability of the Cambrian Richard R Jackson, Ilaria De Santo, Peter Weinheber, SPE, Schlumberger, Em Abstract Wireline formation testing (WFT) and flui Jiang YiMing, Sandeep Chakravorty, and�J. Robert Marsden, Schlumber Abstract Renewed interest in fractures and faults i Kalyan Chakraborty and Mubarak Al-Hajeri, Kuwait Gulf Oil Co., and Jayant Abstract Stratigraphic trapping mechanism plays a Layla Saleh Al Muhairi, Maria Teresa Ribeiro, Agung Dharmawan, and Mo Abstract A Geological Model was built and an Unc Y. Z. Ma, SPE, Schlumberger; A. Seto, SPE, Pengrowth Corp.; and E. Gom Abstract As a branch of spatial statistics geostatis M. Claverie, Schlumberger; S. Aboel-Abbas, C.S. Mutiara; and H. Harfoush Abstract Thinly bedded reservoirs are increasingl C.C. Minh, Schlumberger, and P. Sundararaman, Chevron Abstract We use nuclear magnetic resonance (NM Aristides Orlandi Neto, SPE, and Dhruba Dutta, SPE, Schlumberger, and S Abstract As the global power scenario changes w G.A. Bordakov, A.V. Kostin, J. Rasmus, D. Heliot, SPE, Schlumberger;and Summary The paper illustrates the improvements Khalid H. Al-Azmi, SPE, Hamdah Al-Enezi, SPE, Rohitkumar Kotecha, and Abstract The Greater Burgan Field consists of thr Vasudev Singh, SPE, Nicolas P. Roussel, SPE, and Mukul M. Sharma, SPE,Abstract U The production and injection of fluids in a A. Abdulraheem, KFUPM, M. Ahmed and A. Vantala, Schlumberger, and T. Abstract Rock mechanical parameters of reservo Bikash Sinha, SPE, Tom Bratton, SPE, Jesse Cryer, Steve Nieting, Schlum Summary Highly depleted reservoirs exhibit sharp B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, SPE, Schlumberger Abstract This paper presents the results of an inv B.D. Poe Jr., SPE, W.K. Atwood, SPE, J. Kohring, SPE, and K. Brook, SPE Abstract This paper presents the results of an inv B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, SPE, Schlumberger Abstract This paper presents the results of an inv Pradyumna Dutta, Sunil Kumar Singh, and Jarrah Al-Genai, Kuwait Oil Co Summary The Najmah Sargelu and Marrat reser Essam A.E.A. Bassim and Kaoru Yamaguchi, Arabian Oil Company, Ltd., a Abstract The carbonate reservoirs in Gulf of Suez O. Pinous, Schlumberger; Abdel M. Zellou, Gary Robinson, and Ted Royer, Abstract The field is located in the southeastern p Sandeep Chakravorty, Schlumberger Middle East S.A.; Jean-Louis Lesueur, Abstract The oil-bearing Upper Jurassic Arab rese O. Pinous, Schlumberger; E.P.Sokolov and S.Y.Bahir, Russneft; Abdel M. ZeAbstract The Maloichskoe field is located in the s

Fikri Kuchuk, SPE, and Lang Zhan, SPE, Schlumberger; S. Mark Ma, SPE, Abstract In this paper we present a novel method Hussain A. Al-Jeshi, Charles Bradford, Saudi Aramco; Murat Zeybek, Schlu Abstract The process of defining the fluid and res Cosan Ayan and Mario Petricola, Schlumberger, and Philip Knight and BrunoAbstract Wireline Formation Tester (WFT) pretest Long Jiang and Keith Schilling, Schlumberger; Jim Logan, Chevron OffshoreAbstract Acoustic measurements have long been Omar Aguirre and Juan Carlos Glorioso, Repsol YPF, Jeannette Morales a Abstract We have validated with superior results t Chanh Cao Minh, Peter Weinheber, Wich Wichers, and Adriaan Gisolf, Schlumb Abstract One of the most important objectives of f M. Claverie, D. Maggs, and M. Van Steene, Schlumberger, and D. WestacottAbstract The analysis of shaly sand gas reservoir H.N. Bachman, SPE, S. Crary, SPE, R. Heidler, and J. LaVigne, SPE, Schl Abstract An ongoing challenge for nuclear magne Robert Freedman, Schlumberger Oilfield Services Distinguished Author Series articles are general d Franco Vittore and Javier Pompei, Repsol YPF, and Oscar Ortiz and Anthon Abstract Up to now different petrophysical method Ahmed S. Al-Muthana, SPE, and S.M. Ma, SPE, Saudi Aramco; M. Zeybek, Abstract Currently many of the producers are ho S. Al Arfi, ADCO, and D. Heliot, J. Li, X. Zhan, and D. Allen, Schlumberger Abstract A new methodology for porosity and perm Torsten Friedel, George Mtchedlishvili, Hans-Dieter Voigt, and Frieder H� Summary Underbalanced drilling (UBD) is defined Taher El Gezeery, SPE, Kuwait Oil Company, Fawaz Al Saqran, Kuwait Oil Abstract The Minagish structure in southwest corn Hani Elshahawi, Shell; Lalitha Venkataramanan, Schlumberger; Daniel McK Summary Identifying compartmentalization and u Chengli Dong, SPE, Schlumberger; Hani Elshahawi, SPE, Shell; Oliver C Abstract Understanding reservoir architecture is c Soraya S. Betancourt, Francois X. Dubost, and Oliver C. Mullins, Schlumbe Abstract Compartmentalization is perhaps the sing B.D. Poe Jr., W.K. Atwood, J. Kohring, and K. Brook, Schlumberger Abstract This paper presents the results of an inve Mike Burke, SPE, and M. Bremeier, SPE, Wintershall Libya; Mohamed Sheba Abstract Residual oil estimations are mainly based Nicolas Orban, Cosan Ayan, and Mario Ardila, Schlumberger Abstract Many sedimentary features of gas fields H. Elshahawi, Shell Intl. E&P Inc.; E. Donaghy and C. Guillory, Shell Oil C Abstract WBased Lithofacies Mapping Ayan C. and Achourov V., SPE, Schlumberger, Alpatov A., SPE, Sibneft-KhaAbstract Waterflood management requires the op R. Banerjee, SPE, R.K.M. Thambynayagam, SPE, and J. Spath, SPE, Schlum Abstract Interpretation of pressure transient tests E. Kasap, Schlumberger; G.J. Sanza, and M.I. Ali, Petronas Carigali; T. Fr Abstract A revised Field Development Plan (FDP) J.M. Muruais, SPE, Schlumberger, and A.A. Young, SPE, Anzon Australia Lt Abstract One of the challenges that operating com Mahmoud A. Wahba, Maharon Jadid, Ibrahim B. Subari, and M. Nazli B. AbuAbstract As production declines and watercut inc W. Gaviria, SPE, and J.G. Flores, SPE, Schlumberger, and J. Lorenzon, SPE, Abstract Breathing new life into a mature oil field G. Kartoatmodjo, R. Strasser, and F. Caretta, SPE, Schlumberger; M. Jadid Abstract Proper fieldwide production surveillance Phil Warran, SPE, Nidal Mishrafi, SPE, and Saleh M. Dossari, SPE, Saudi Abstract Saudi Arabia is blessed with the world†Abdel Nasser Abitrabi B., Ali Rabba, Waleed Amoudi, and Abdallah M. BehaiAbstract Targeting thin sand bodies while drilling a N. Behl, K.E. Kiser, and J. Ryan, Schlumberger IPM Abstract Production from low-pressure gas wells Torsten Friedel, Ramiro Trebolle, Stephen Flew, William Belfield, Juergen Abstract A novel workflow methodology that cove J. Moreno, A. Badawy*, G. Kartoatmodjo, H. AlShuraiqi, F. Zulkhifly, L. Ta Abstract Reservoir management is a standard ind A. Alvarez, E. Guerra, A. Gammiero, C. Velasquez, J. Perdomo, and R. H Abstract Pursuing new alternatives to develop an B. Gűyagűler, SPE, Chevron, and K. Ghorayeb, SPE, Schlumberger Abstract Field management (FM) is the simulation Fernando Gutierrez, Aron Hallquist, Mack Shippen and Kashif Rashid, Sch Abstract One of the most common methods of inc T. Friedel, SPE, Schlumberger; G.J. Sanza, M.I. Ali, and A. Embong, SPE, Abstract A reservoir simulation model calibrated w Antonio Cuauro, SPE, Schlumberger, Mohd Izat Ali, Maharon Bin Jadid, SP Abstract Betty is an oil field discovered in 1968 an E. Valbuena, J.L. Bashbush, and A. Rincon, Schlumberger Abstract Steam injection projects consume consid Emad Elrafie, Isabelle Zabalza-Mezghani, Tariq Abbas, Saudi Aramco, Yako Abstract Integrated reservoir studies aim at synerg �ystein Tesaker, Alf Midtb� �verland, and Dag Arnesen, StatoilHydr Abstract The objective of this paper is to highlight A. Howell, Schlumberger Information Solutions; M. Szatny, Aspen Technology Abstract Simulation technology from reservoir thr Fernando L. Morales and Juan Cruz Vel�zquez, Schlumberger, and Aar Abstract Traditionally in the upstream business op T. Graf, R. Dandekar, and C. Amudo, SPE, Schlumberger Abstract With multi-processor cluster computing Zhizhuang Jiang and Zhang Tao, ConocoPhillips, China Inc., and Khong Ch Abstract The China National Offshore Oil Corpora Jose G. Flores, SPE, and Jon Elphick, SPE, Schlumberger, and Francisco LAbstract The production of large volumes of water M.A. Al-Khaldi and E.O. Ghoniem, Al-Khafji Joint Operations, and A.A. Jam Abstract The gas lift by limited capacity of 25 M You Hongqing, Wei Ping, Tian Xiang, Xu Xiang Dong, Lian JiHong, Thanh TrAbstract The Huizhou 6S and 3S oil fields in the P G.C. Dozier, SPE, Schlumberger, and P. Giacon, SPE, Petroleum Develop Abstract This paper will illustrate the collaborative Li Fan, Ronald B. Martin, Baljit Sehbi, Keith W. Owen, W.K. Atwood, and J Abstract This paper presents a unique workflow fo M. Prange, SPE, Schlumberger-Doll Research; M. Armstrong, SPE, Cerna, Eco Abstract In conditions of high demand for rigs and

Raphael Altman, Paolo Ferraris, and Fabricio Filardi, Schlumberger Abstract This account describes how advanced w Ken Halward, Joe Emery, and Rod Christensen, Oilexco; Daniel Bourgeois aAbstract In 2006 Oilexco North Sea Limited deve N. Liu, Chevron ETC, and Y. Jalali, SPE, Schlumberger Abstract We present a methodology of converting M. Parker, Kerr McGee; R.N. Bradford, Callon Petroleum; and C. Corbett, Abstract Well placement decisions are routinely m Patrick W. von Pattay, SPE, Jeff Hamer, SPE, and Ralf Strasser, SPE, Sch Abstract This paper presents an innovative filterin G. Kartoatmodjo, C. Bahri,* A. Badawy,* N. Ahmad, J. Moreno, B. Wu, F. Zu Abstract Planning of infill drilling in oil rim reservo M.J. Zandvliet, SPE, M. Handels, SPE, G.M. van Essen, SPE, Delft UniversitSummary Determining the optimal location of wel M. Nukhaev, V. Pimenov, A. Shandrygin, and V. Tertychnyi, Schlumberger Abstract Steam chamber (SC) control during stea G. Busswell, SPE, R. Banerjee, SPE, R.K.M. Thambynayagam, SPE, and J.Abstract We present a set of new analytical solut J. Phillip Gilchrist, Geoff Busswell, Raj Banerjee, Jeff Spath and R.K. Mi Abstract We present new semi-analytical solutions A.M. Daoud, SPE, and L. Vega, SPE, Texas A&M U. Abstract Conditioning geologic models to product Ramez Azmy, SPE, Ahmed M. Daoud, SPE, Khaled A. Fattah, SPE, and M.H. Abstract Adjoint method-based sensitivity for field J.S. Al-Thuwaini, Saudi Aramco; G. Zangl, Schlumberger; and R. Phelps, S Abstract The study objective is to investigate the C. Amudo, Chevron Australia Pty. Ltd.; T. Graf, Schlumberger; N.R. Harris, Abstract With the increasing acceptance of stoch S. Yadav, Schlumberger Abstract This paper presents a novel methodolog Torsten Friedel, SPE, Schlumberger, and Hans-Dieter Voigt, SPE, Freiberg UAbstract T Sensitive Permeability Xundan Shi and Yih-Bor Chang, Chevron; Mathieu Muller and Eguono Obi, Abstract We describe the construction of a gener H. Cao and P.I. Crumpton, Schlumberger, and M.L. Schrader, Chevron En Abstract This paper describes a general formulati Y. Wang, SPE, J. Moreno, SPE, and J.H. Harfoushian, SPE, Schlumberger Abstract Horizontal wells often present a substan S. Mubarak, N.I. Al-Afaleg, and T.R. Pham, Saudi Aramco, and M. Zeybek a Abstract T Contact (MRC) Well Yuandong Wang, SPE, Dan Shan, SPE, and Robin N. Heim, SPE, SchlumbAbstract Horizontal and multi-lateral wells have be Ghazi D. Al-Qahtani, Emad A. Elrafie, Raja T. Abbas, Clara E. Ikuku, and Abstract The application of Complex Wells (CW) Nick Koutsabeloulis, SPE, and Xing Zhang, SPE, Schlumberger Reservoir Abstract The pore pressure stress state and geo C.K. Huang, Y.K. Yang*, M.D. Deo, University of Utah Abstract In a thermal-compositional reservoir sim Samuel Aderemi, SPE, and Kingsley Akpara, SPE, Schlumberger InformatioAbstract Decline curve analysis is a graphical pro R. Barati, SPE, University of Kansas; R.D. Hutchins, SPE, T. Friedel, SP Summary The fracture-propagation process perfo T. Friedel, Schlumberger Data & Consulting Services Abstract To exploit the substantial tight-gas resou Arash Soleimani, SPE, Schlumberger; Byung Lee, SPE, Saudi Aramco; andAbstract Horizontal wells with multiple fractures a O. Dinariev, IFZ RAS; A. Shandrygin, SPE, D. Rudenko, SPE, and V. Terty Abstract High accurate reservoir simulation is req H. Gu, SPE, E. Siebrits, SPE, and A. Sabourov, SPE, Schlumberger Abstract Interfacial slip is one of the mechanisms H. Sadrpanah, SPE, Schlumberger, and T. Charles and J. Fulton, Total E&P Abstract This paper presents explicit simulation H. Huang, Georgia Inst. of Technology, and J.A. Ayoub, Schlumberger Abstract Non-Darcy flow reduces the productivity o Leonardo Vega, Schlumberger, DCS Abstract Wells in tight gas reservoirs are often com B.D. Poe Jr., SPE, Schlumberger Abstract This paper presents the results of an inv Olivier Li�tard, Consultant, and Jerome Mani�re and Mark Norris, Sch Abstract The expansion of horizontal well technolo S.G. Cherny, V.N. Lapin, and D.V. Chirkov, Institute of Computational Te Abstract The goal of this paper is to investigate th D. Kaviani, SPE, Texas A&M U.; T.D. Bui, SPE, Schlumberger; J.L. Jensen*,Summary Artificial neural networks (ANNs) have b Majid Mohammadpour Faskhoodi*, SPE, Harun Ates, SPE, and Tono Soeriawina Abstract To predict future reservoir performance a Ahmed Daoud, SPE, Osama Hegazy, Yasser Hazem, Mohamed Lotfy, SamirAbstract Y Gas reservoirs in the Nile Delta of Egypt Guohua Gao, SPE, Chevron Corp.; and Younes Jalali, SPE, Schlumberger Summary This paper presents a mathematical mo J.J. Elphick, SPE, and L.J. Marquez, SPE, Schlumberger, and�M. Amaya,Abstract Oil viscosities of about 2 cP and above ( T. Bui, SPE, Schlumberger; M. Bandal, SPE, and N. Hutamin, SPE, Petronas; Abstract In this paper we present the results of a Carlos A. Garcia and Jose R. Villa, U. Central de Venezuela Abstract Original Oil In Place (OOIP) calculations N. Belova and L. Berul, Schlumberger, and A. Sentyuriyev, NOVA TechnologIntroduction The main objective of the mature field Hadi Nasrabadi, Imperial College London, and Kassem Ghorayeb and AbbasSummary We present formulation and numerical C. Amudo, SPE, Chevron Australia Pty Ltd; T. Graf, SPE, and R. Dandekar Abstract With the dearth of easy oil in the industry Y. Wang, SPE, Schlumberger; M. Bandal, SPE, Petronas; J. Moreno, SPE, Abstract The Capillary-saturation function plays a R. Potsepaev, C.L. Farmer, and A.J. Fitzpatrick, Schlumberger Abstract This paper investigates the control volum D.Rudenko, A.Shandrygin and A.Zyryanova, SPE, Schlumberger Abstract The peculiarities of retrograde condensat C.A. Kossack, SPE, Schlumberger Abstract The presence of vugs in a naturally fract Satomi Suzuki, SPE, Stanford U.; Colin Daly, SPE, Schlumberger; Jef Caers,Summary The application of elastic stress simula

Kassem Ghorayeb, SPE, Manoch Limsukhon, SPE, Schlumberger, Qasem D Abstract The North Kuwait Jurassic Complex cons A. Kozlova, Schlumberger Moscow Research; F. Bratvedt, Schlumberger Inf Abstract Streamline methods as a reservoir simul Nikolay Andrianov, Kyrre Bratvedt, and Artyom Myasnikov, Schlumberger Abstract Naturally fractured reservoirs can be see J.R. Natvig and B. Skaflestad, SINTEF�ICT; F. Bratvedt and K. Bratvedt, Abstract Advances in reservoir characterization a David O. Ogbe, SPE, Fabian O. Iwere, SPE, Linda Boukhelifa, SPE, Erni Abstract Conceptual models are used to solve spe Guohua Gao, SPE, Chevron Corp.; Mohammad Zafari, SPE, Schlumberger;Summary a The well known PUNQ-S3 reservoir mo G. Zangl, SPE, and T. Graf, SPE, Schlumberger, and A. Al-Kinani, SPE, Min Abstract Proxy models are becoming more widel Tharwat Fawzy, Schlumberger, and Eric Mackay, Heriot-Watt University Abstract Inorganic scales precipitate in oilfield sys Adriaan GISOLF, Francois DUBOST Julian ZUO, Schlumberger, Stephen Abstract The increasing complexities of newly disc K. Gonzalez, J.L. Bashbush, and A. Rincon, Schlumberger Abstract Steamflood with conventional vertical we Nikolay Andrianov and Kyrre Bratvedt, Schlumberger Abstract Streamline methods have become an eff Olga Podgornova, Artyom Myasnikov, and Kyrre Bratvedt, Schlumberger; Abstract One of the most challenging problems fo A. Al-Kinani, G. Nunez, M. Stundner, G. Zangl, and O. Iskandar, SPE, Sch Abstract This paper discusses a new workflow to Mohammad Zafari, SPE, Schlumberger; and Albert C. Reynolds, SPE, U. of Summary Recently the ensemble Kalman Filter ( S. Yadav, Schlumberger, and S.L. Bryant and S. Srinivasan, U. of Texas at Abstract This paper presents a novel approach to K. Neylon, SPE, Schlumberger; E. Reiso, StatoilHydro ASA; J.A. Holmes, Abstract We present a model for well inflow contr Kassem Ghorayeb, SPE, and Jonathan Holmes, SPE, Schlumberger Summary Black-oil reservoir simulation still has w Kassem Ghorayeb, SPE, and Manoch Limsukhon, SPE, Schlumberger, and Abstract The North Kuwait Jurassic Complex (NK Bernard Montaron, SPE, Schlumberger Abstract Reservoir rock wettability is an important Kaibin Qiu, Schlumberger; Yousef Gherryo and Mohamed Shatwan, AGOCOAbstract ( An experimental study was conducted on H. Huang, SPE, and J. Ayoub, SPE, Schlumberger Abstract The subject of non-Darcy flow in hydraul A.J.G. Carnegie, Schlumberger Abstract Worldwide carbonate oil-water transitio J. Capps and R. Khamatdinov, Margham Dubai Establishment; and S. ShayeAbstract The Margham gas field discovered in the Dhruba J. Dutta, SPE, Ahmed Abu El Fotoh, and Dedi Juandi, Schlumberge Abstract Borehole instability in most of the cases R. Murray, SPE, BP Exploration; C. Edwards, SPE, Shell; K. Gibbons, SP Abstract This paper summarizes the findings of t A.N. Shandrygin, SPE, Schlumberger, and A. Lutfullin, State Commissio Abstract Russia is one of the main oil producing c J.A. Walker, SPE, ConocoPhillips Alaska Inc.; D.O. Ogbe, SPE, Schlumberge Abstract Alaska’s North Slope and the United Simon James, SPE, and Linda Boukhelifa, SPE, Schlumberger Summary Over the past 10 years several papers M. Claverie, SPE, Schlumberger; N.A. Malek, SPE, Petronas Carigali; and Abstract After more than 20 years of exploitation Jeffrey Grant, Dale May and Keith Pinto, Schlumberger Abstract Pulsed neutron measurements have bee M. Van Steene, SPE, B. Herold, SPE, D. J. Dutta, SPE, Y. Abugren, S. Hos Abstract Accurate time-lapse saturation informatio M. Zakharov, Schlumberger; S.H. Eriksen, Hydro Oil & Energy; and I. Raw, Abstract During the last decade intelligent well co Koksal Cig and Ihsan Gok, Schlumberger Abstract The new production logging tool string a D.E. Fitz, ExxonMobil Upstream Research Co.; Angel Guzm�n-Garcia, Exx Abstract Production logging and flow profile interp B.C. Theuveny, P.D. Maizeret, N.S. Hopman, and S. Perez, Schlumberger Oil Abstract The identification of condensate banking K.D. CONTREIRAS and F. VAN-D�NEM, Sonangol P & P; P. WEINHEBER, Abstract The combination of low permeability oil b K.D. Contreiras and F. Van-Duinem, Sonangol P & P; P. Weinheber, A. GisolAbstract The combination of low permeability oil b Abdullatif Al-Omair, SPE, Orji O. Ukaegbu, SPE, and Muhammed Alshafie, Abstract This paper describes an innovative Dow B. Raghuraman, SPE, and M. O'Keefe, SPE, Schlumberger; K.O. Eriksen, SP Summary A new downhole pH sensor has been d R.A. Holicek, J. Adachi, L.A. Viloria, A.I. Mese, and Y. Traore, Schlumberg Abstract With increasing availability of real-time do Leo Eisner, Schlumberger Cambridge Research; Tomas Fischer and ZuzanaAbstract A multistage hydraulic fracture treatment George C. Dozier, Schlumberger Abstract Fracture height prediction and evaluation A. Al-Behair, Saudi Aramco, S. Malik and M. Zeybek, Schlumberger, A. Al-H Abstract Accurate diagnostics of wellbore fluid ent P. Krawchuk, SPE, and M.A. Beshry, Total E&P Canada, and G.A. Brown, Abstract During the start-up and early operation o B.D. Poe Jr., SPE, and R.J. Butsch, SPE, Schlumberger Abstract This paper addresses some recent deve B.D. Poe Jr. and R.J. Butsch, Schlumberger Abstract This paper presents some recent develop H. Huebsch, M. Moss, and T. Trilsbeck, EnCana, and G. Brown, S. Rogers, Abstract Fiber-optic systems are able to generate Ali Bakhshi, SPE, Woodside Energy Ltd; Peter Scaife, Tracerco; and Ian M Abstract This paper presents the first case study M. Webster, SPE, and S. Richardson, SPE, BP Exploration; C. Gabard-Cuo Summary Flow rate and fluid type (phase) are two Hassan Bahrami, Sharif University of Technology; Jamal Siavoshi, Husky Abstract Fractures identification is essential durin Chen Jiun Horng @ Chris; Norbashinatun Salmi Nordin; M Azrul Nuriyadi; 0

Michael Stundner and Gustavo Nunez, Schlumberger, and Frank M�ller NiAbstract The availability of accurate performance K. I. Ojukwu, M.I. Khalil, J. Clark, H. Sharji, Petroleum Development Oman Abstract Production logging low flow rate wells is Anil Ambastha, SPE, Chevron; Qasem Dashti, SPE, Kuwait Oil Company; PiAbstract The Wara reservoir has been producing f P.E. Parta, SPE, A. Parapat, R. Burgos, SPE, J. Christian, SPE, and A. J Abstract In this paper we present a field example K.M. Hanafy, SPE, GUPCO, and T.A. Elsherif, SPE, Schlumberger Abstract With the dramatic increase in oil prices H. Elshahawi, SPE, M. Hashem, SPE, and D. McKinney, Shell International Summary Modern wireline formation testers (WFT G.A. Brown, SPE, Schlumberger Abstract Early identification of differential depletio S.C. Maxwell , J. Du, J. Shemeta, U. Zimmer, N. Boroumand, and L.G. Griff Summary A combination of microseismic and surf I.D. Pinzon, SPE, J.E. Davies, SPE, BP, F. Mammadkhan, SPE, and G.A. Abstract BP is developing its Azeri field using dev S. Mackay, SPE, J. Lovell, SPE, D. Patel, SPE, F. Cens, SPE, and S. Esca Abstract The expense of subsea well intervention Bingjian Li1, Hamad Najeh2, Jim Lantz3, Mansoor Ali Rampurawala4, Ihs Abstract One of the key issues in creating a good B. Theuveny, A. Kosmala, P.-D. Maizeret, and R.K. Sagar, Schlumberger OilfAbstract A A Virtual Dream or Reality? The Case M. Stundner, SPE, and G. Nunez, SPE, Schlumberger Abstract The availability of accurate production vo O. Ojonah, SPE, Shell Production and Development Co., and J.J. Kohring, Abstract Maximising the potential of a producing w P.J. Gauthier and H. Hussain, Petroleum Development Oman; J. Bowling, B Abstract The paper presents a novel logging appr Dhruba J Dutta, SPE, Schlumberger and Abdallah B Badr, SPE, Agiba Pet Abstract Improvement of oil recovery and reductio M. M. Amer, O. Al-Farisi,T. Hiraiwa, M. Attia, A. Al-Habshi, SPE, ADMA-OP Abstract For pressure maintenance purpose perip Zahid Bhatti, Mohamed Shuaib, ADCO, Michael Wilt, Cyrille Levesque, Sc Abstract In the paper we will briefly review the pil Malalla Al Ali, Volker Vahrenkamp, Saber Elsembawy, and Zahid Bhatti, AD Abstract Time-lapse cross-well electromagnetic (E P.M. Snider, SPE, Marathon Oil Co.; I.C. Walton, SPE, Schlumberger; T.K Summary Worldwide Coal Bed Methane (CBM) re Mohammad Ali (ONGC), Arpana Sarkar (Schlumberger), Rajiv Sagar (Schlum Abstract Fracture systems comprise the primary f T.N. Olsen, T.R. Bratton, A. Donald, R. Koepsell, and K. Tanner, Schlumber Abstract Propped hydraulic fracture stimulation ha A.A. Ketter and J.R. Heinze, Devon Energy, and J.L. Daniels and G. Water Summary The Barnett shale is an unconventiona R. Su�rez-Rivera, SPE, and S.J. Green, SPE, TerraTek Inc.; J. McLennanAbstract Hydraulic fracturing is the requisite meth Abbas Mahdi, Schlumberger; Mike Yu, EnCana Corp.; and Doug Pipchuk, CAbstract Nitrogen coiled tubing fracturing is the pr G. Waters, SPE, Schlumberger; J. Heinze, SPE, R. Jackson, SPE, and A. K Abstract Horizontal wells represent a growing per C. Du, SPE, X. Zhang, SPE, B. Melton, D. Fullilove, B. Suliman, SPE, S. G Abstract The Mississippian Barnett Shale reservo F. Akram, SPE, Schlumberger Canada Ltd. Abstract Estimated at 2.5 trillion barrels Canada h Creties D. Jenkins, SPE, DeGolyer and MacNaughton, and Charles M. BoyeDistinguished Author Series articles are general d D.I. Potapenko, S.K. Tinkham, B. Lecerf, C.N. Fredd, M.L. Samuelson, M.R.Abstract Gas production from the unconventional F.F. Chang, SPE, and M. Abbad, Schlumberger Abstract The chemical nature of carbonate rocks Ahmed R. Al Zahrani, SPE, Redha H. Al-Nasser, SPE, and Timothy W. Col Abstract The Electrical Submersible Pump (ESP) F. Gaviria, SPE, SUNCOR, and R. Santos, SPE, O. Rivas, SPE, and Y. Luy Abstract The need for high-temperature electric s Siddhartha Gupta, Schlumberger Abstract Artificial lift systems are now being consid Sergey Ryzhov, SPE, Vladimir Malyshev, SPE, Shlumberger, and Tatyana K Abstract The Sporyshevskoye oil field developme A. Calderon, SPE, A.F. Arag�o, SPE, and C.M. Chagas, SPE, PETROBR Abstract The offshore northeast Brazil Manati fiel Gary Rytlewski, Schlumberger Abstract A new method of completing multiple-laye Surej Subbiah/Schlumberger; Wielemaker.E/Schlumberger; Joia P/Petrom Abstract Cartojani is a mature oil field with deplet B.D. Poe Jr., SPE, Schlumberger Abstract This paper presents the results of an inv B.D. Poe Jr., SPE, Schlumberger Abstract This paper presents the results of an inv M. Kabir, KOC; S. Ingham, Schlumberger; D. Sibley, K. Osman, A.K. Amba Abstract Mauddud reservoir in the Greater Burgan Liu Song, Li Jianping, and Lv Dingyu, CNOOC, and Jeffrey Kok and Shim Abstract The lower Minghuazhen is a shallow-wa S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. Abstract This paper describes a case-study detail T.S. Ramakrishnan, Schlumberger-Doll Research Summary Poor displacement efficiency in hydroca S.M. Mubarak, T.R. Pham, and S.S. Shamrani, SPE, Saudi Aramco, and M. Summary This paper describes a case study that Jose R. Amorocho, J. Ricardo Solares, Abdulmohsin Al-Mulhim, and Ali Al Abstract The number of multilateral gas producer Mohammed M. Amro, SPE, and Mohamed S. Benzagouta, SPE, King Saud Abstract Univ Current drilling technology is moving tow J. Jaua and O. Rivas, SPE, Schlumberger, and A. Mej�as, Repsol YPF Abstract As a result of the increasing emphasis o W.J. Bailey, SPE, Schlumberger-Doll Research; I.S. Weir, U. West of Eng Summary A rigorous statistical methodology using F.O. Garzon, H.M. Al-Marri, J.R. Solares, and C.A. Franco Giraldo, SPE, Abstract Acid Fracturing has been a successful m Tim S. Schneider, David O. Uldrich, and Richard Hodge, ConocoPhillips Co Abstract The Alpine field located on the North Slop

A. Powell, Headington Oil Co., O. Bustos, W. Kordziel, T. Olsen, D. Sobern Abstract Since the horizontal lateral Bakken dolom D. Oussoltsev, SPE, K. K. Butula, SPE, and A. Klyubin SPE, Schlumberger, Abstract Successful hydraulic fracturing in various Maytham I. Al-Ismail, SPE, Moataz M. Al-Harbi, SPE, and Abdulaziz K. A Abstract Acid fracturing has been part of Saudi Ar S. Sitdikov, SPE, A. Serdyuk, and A. Nikitin, SPE, Rosneft, and A.Yudin, Abstract This paper describes successful implem Paul R. Howard, Sumitra Mukhopadhyay, Nita Moniaga, Laura Schafer, Sc Abstract Flowback aids are usually surfactants or Hongren Gu, SPE, and Eduard Siebrits, SPE, Schlumberger Summary Much study has been conducted on the Daren Bulat, SPE, Talisman Energy Inc., and Yiyan Chen, Matthew K. Gra Abstract Natural gas reservoir development contin S.M. Rimassa, SPE, P.R. Howard, SPE, and K.A. Blow, SPE, SchlumbergerAbstract As mature fields produce larger quantities Bilu Cherian, SPE, Schlumberger; Kirk Fields, SPE, and Seth Crissman, SP Abstract The key to the success of a tight-gas fiel O. Hidalgo, Schlumberger Well Services; O. Gonz�lez and V. Gonz�le Abstract Frac-pack is a pervasively used complet A.V. Yudin and K.K. Butula, Schlumberger, and Y.V. Novikov, OAO Tomskne Abstract The productive pay of the low permeabilit Majdi Al Mutawa, SPE, Bader Al Matar, SPE, and Yousef Abdul Rahman, SPAbstract In the recent years horizontal well techno R. Arangath, SPE, Schlumberger, and J.F. Obamba, SPE, P. Saldungaray, Abstract A common scenario in many mature oil Pedro Saldungaray, Schlumberger; Efrain Huidobro Salas, Pemex; Sebast Abstract Latin America hasn’t escaped the ge Alberto Casero, SPE, and Giamberardino Pace, SPE, Eni E&P; Brad MaloneAbstract Many West Africa offshore fields are mat J.R. Solares, SPE, C.A. Franco, SPE, H.M. Al-Marri, SPE, and H.A. Al-J Abstract One of the key strategies in Saudi Aramc Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract Offshore operations are extremely expen Tomislav Bukovac, Rafik Belhaouas and Daniel Perez, SPE, Schlumberger; Abstract CuFree Fluid System, Executed from a S Rajiv Sagar, Schlumberger; A.K. Pandey, Durga Prasad, A.K. Vinod ONGC, Abstract Gandhar is one of ONGC’s major bro B.D. Poe Jr., SPE, Schlumberger, and J.F. Marique, SPE, Consultant Abstract This paper presents the results of an inv T.N. Olsen, T.R. Bratton, and M.J. Thiercelin, Schlumberger Abstract Since the widespread proliferation micro A.N. Parfenov, SPE, S.S. Sitdikov, SPE, O.V. Evseev, SPE, and V.A. Shash Abstract The majority of hydraulic fracturing work George Waters, Barry Dean, and Robert Downie, Schlumberger, and Ken KeAbstract Hydraulic fracturing of horizontal wells in G. Rytlewski and J. Lima, Schlumberger, and B. Dolan, Petrogulf Abstract A new method of completing multiple laye G.L. Rytlewski and J.M. Cook, Schlumberger Abstract A new method of completing multiple-lay Olga Alekseenko, Schlumberger Abstract Petroleum engineers have faced the pro P.F. Sullivan, B. Gadiyar, R.H. Morales, R. Hollicek, D. Sorrells, and J. Le Abstract Visco-Elastic Surfactant (VES) fluids are M.E. Semmelbeck, W.E. Deupree, and J.K. von Plonski, SPE, Escondido Resou Abstract A novel carbon dioxide- (CO2-) emulsifi Vibhas J. Pandey and Tarik Itibrout, SPE, Schlumberger; Larry S. Adams, Abstract This paper discusses the selection criter P. Parra, E. Miquilena, A. S�nchez, and A. Pe�a, Schlumberger Well Abstract T Permeabili Generation Viscoelastic Flu Areiyando Makmun, Schlumberger, and Fathi Issa and Gadalla Hameed, Si Abstract Offshore A drilling program on North Rag Qasem Dashti, SPE, Mir Kabir, SPE, Raju Vagesna, SPE, Feras Al-RuhaimaAbstract This paper presents the process of candi J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. Van der Bas, SP Abstract It is well documented in the literature tha Jason Baihly, Schlumberger; Andrew Coolidge and Steven Dutcher, Devon; aAbstract Microseismic hydraulic fracture monitorin Torsten Friedel, George Mtchedlishvili, Aron Behr, Hans-Dieter Voigt, and Fr Abstract Productivity impairment in tight-gas forma P. Bulant, Charles U.; L. Eisner, Schlumberger Cambridge Research; I. PŠSummary Significant errors in the calculated azim M.N. Bulova, SPE, A.N. Cheremisin Jr., SPE, K.E. Nosova, SPE, J.T. Lasse Abstract Permeability Formations C. Malagon, SPE, M. Pournik, SPE, and A.D. Hill, SPE, Texas A&M UniversiSummary In an acid-fracturing treatment fracture A. Nikitin and A. Shirnen, Rosneft, and J. Maniere, Schlumberger Abstract The generalization of Hydraulic fracturing R.R. McDaniel, SPE, and J.F. Borges, SPE, Hexion Specialty Chemicals, a Abstract For years radioactive tracers have been Alexey Nikitin, SPE, Rosneft-Yuganskneftegaz; Alexey Yudin, SPE, SchlumbAbstract The focus of our research is on a remote Y. Shumakov, A.A. Burov, and K.K. Butula, SPE, Schlumberger, and I.A. Abstract Though there are many proven ways of A.H. Akram, SPE, and A. Samad, SPE, Schlumberger Abstract A study was carried out to forecast the p V.M. Entov, Inst. for Problems in Mechanics, Russian Academy of Scienc Abstract Pressure distribution at the tip of a hydra H.A. Nasr-El-Din, SPE, S. Al-Driweesh, SPE, and K. Bartko, SPE, Saudi A Abstract The deep tight carbonate formations in J.F. Manrique, SPE, Occidental Oil and Gas Corp., and B.D. Poe Jr., SPE, Abstract This paper presents the results of an inv S.C. Maxwell, U. Zimmer, R. Gusek, and D. Quirk, Pinnacle Technologies Summary Microseismic imaging of a hydraulic-fra G.R. Aidagulov and M. Thiercelin, Schlumberger, and V.N. Nikolaevskiy, S.MAbstract Proppant flowback is an extremely impor X. Weng and E. Siebrits, Schlumberger Abstract In this work the propagation of an orthog Smirnov N.N., Kisselev A.B., Nikitin V.F., and Zvyaguin A.V., Moscow M.V. Abstract The practical problem arises in enhancin A. Nikitin and A. Pasynkov, Rosneft YNG, and G. Makarytchev, J. Maniere Abstract In a waterflooded reservoir hydrocarbon

J.A. Ayoub, SPE, and R.D. Hutchins, SPE, Schlumberger; F. van der Bas, SP Abstract This paper summarizes part of the resu Tamara Webb, Jusni Omar, Murphy Oil Corporation, Saifon Daungkaew, LeeAbstract Kikeh Field is a deepwater project locate Almeida, C.M.C. de, Schlumberger; Melo, R.L.C., Petrobras; Holzberg, B. Abstract Hydraulic fracturing plays a very importa R.G. Jeffrey and X. Zhang, SPE, CSIRO Petroleum, and M. Thiercelin, S Abstract Offsets along the hydraulic fracture path Adam Vasper, SPE, Schlumberger Summary The terms auto natural and in-situ gas S.D. Cooper, S. Akong, K.D. Krieger, A.J. Twynam, F. Waters, and R. Morris Abstract BP Trinidad and Tobago (bpTT) has been K. M. Al-Naimi, SPE, B. O. Lee, SPE, K. M. Bartko, Saudi Aramco, S. K. Ke Abstract Horizontal completion technology has pro K. M. Al-Naimi, B. O. Lee, S. M. Shourbagi, Saudi Aramco, S. K. Kelkar, M Abstract Horizontal completion technology has pro Hassan Chaabouni, Schlumberger, Pierre Baux, Dasa Manalu, Muhammad So Abstract Completing horizontal wells with openhol Muhammad Shafiq and Athar Ali, SPE, Schlumberger; and Haider Al-Haj, Abstract This paper describes an innovative comp E. Davila, R. Almeida, I. Vela, J. Pazos, and K. Coello, Petroamazonas;ï¿ Abstract Horizontal wells are superior in productio M.A. Ali, SPE, and M. Shafiq, SPE, Schlumberger Abstract Intelligent completions have been in com Mohammed A. Abduldayem, SPE, Saudi Aramco, Muhammad Shafiq, SPE, Abstract Sch This paper describes an innovative comp E.A. Addiego-Guevara, SPE, and M.D. Jackson, SPE, Department of Earth Abstract Significant challenges remain in the deve L. Casas and J.L. Miskimins, Colorado School of Mines, and A. Black and S Abstract The design and subsequent results of a R. North, SPE, C.P. Lenn, SPE, and I. Stowe, SPE, Schlumberger Abstract A new processing workflow has been en Saifon Daungkaew, Michel Claverie, Boon Cheong, Steve Hansen, Richar Abstract As the cost of exploration wells continue M. A. Mohiuddin, Schlumberger, M. M. Najem, Y. R. Al-Dhaferi, H. A. BajunaiAbstract Sanding problems are often observed in Kirk M. Bartko, Saudi Aramco, and Frank F. Chang, Larry A. Behrmann, and Abstract It is well known that in cased-hole compl Achille Tiribelli, Giovanni Luca Minneci, and Ahmed Daoud, Groupement Abstract The transition from completion to produc M.I. Omar, SPE, A. Md Ali, SPE, and Z. Ali, Petronas Carigali Sdn. Bhd., Abstract Coiled tubing has been widely used worl M. Medina, SPE, Helix RDS; G. Morantes, SPE, and J. Morales, PDVSA; a Abstract Located in Eastern Venezuela the Santa Italo Pizzolante, Steve Grinham, Tian Xiang, and Jihong Lian, CACT Oper Abstract China National Offshore Oil Corporation Cesar Gama, David Gerez, and Paul A. Babasick, SPE, Schlumberger, and Abstract Fracturing is an important technique for s Al-Marri Faisal and Hassan Ibrahim Khalil, ADMA-OPCO, and Alan Salsma Abstract A major challenge identified by ADMA OP Lang Zhan, SPE, Fikri Kuchuk, SPE, Jim Filas, SPE, Dhani Kannan, SPE, Abstract Reliable estimates of post perforation da Graeme Rae, Mohd. Bakri Yusof, and Juanih Ghani, Talisman, and Shahril Abstract In Malaysia coiled tubing (CT) conveyan C. Han, Michael H. Du, and Ian C. Walton, SPE, Schlumberger Abstract A detonated shaped charge fired from a p Hanaey Ibrahim, SPE, and Sameer Balushi, Petroleum Development Oman,Abstract Well productivity is driven by establishing D.C. Atwood, SPE, W. Yang, SPE, B.M. Grove, SPE, L.A. Behrmann, SPE; Abstract We report on a series of laboratory flow e Hanaey Ibrahim SPE, Ali Harrasi, Petroleum Development Oman, Alan Sal Abstract Optimal well productivity is achieved by e Mohammad S. Al-Shenqiti, Alaa A. Dashash, Ibrahim H. Al-Arnaout, Saad MAbstract Saudi Aramco's drilling strategy witnesse C.A. Pedroso, SPE, E.M. Sanches, and N.S. Oliveira, Petrobras, and I.J. Abstract The Campos Basin in Brazil is one of the Luke F. Eaton, SPE, and W. Randall Reinhardt, SPE, ConocoPhillips; J. S Summary ConocoPhillips is developing the Magn Ibrahim Refai, SPE Saudi Aramco, Anwar Assal, SPE Schlumberger, Jere Abstract A number of the wells reach there econom George Colwart, SPE, Robert C. Burton, SPE, Luke F. Eaton, SPE, and R Summary ConocoPhillips is developing the Magn I.O. Yahaya, A. Opusunju, B. Ajaraogu, G. Agbogu, O. Williams, and C. U Abstract Alpha field is situated in SPDC’s OM Brian T. Wagg, SPE, and Jonathan L. Heseltine, SPE, C-FER Technologies Abstract Several operators have recently launched Matthew Law, George W. Chao, Hafeez Ab Alim, and Elsamma Samuel, SchlAbstract The major trend of completion method in Kevin Whaley, Colin Price-Smith, Allan Twynam, and David Burt, BP ExploratAbstract Initial Open Hole Gravel Pack (OHGP) co Ina H. Stroemsvik, Kjell Tore Nesvik, SPE, Frode Vik, and Karin Stene, S Abstract Well Heidrun A-45 located in the Norwe A. Zanchi, Stogit; G. Ripa, M. Colombo, and G. Ferrara, SPE, Eni E&P; and Abstract One of the major challenges in undergro M. Tolan, BG Group, and R.J. Tibbles, J. Alexander, P. Wassouf, L. Schafer Abstract Openhole gravel packing is one of the m Samyak Jain, SPE, Rajesh Chanpura, SPE, Renato Barbedo, and Marcos Abstract Gravel packing has routinely been used E.P. Ofoh and M.E. Wariboko, Nigerian Petroleum Development Co., F.E. UwAbstract A large majority of the recent deepwate Samyak Jain, SPE, Raymond Tibbles, and Jock Munro, SPE, Schlumberger,Abstract Cased-hole gravel packing is commonly Shahryar Saebi, SPE, Samyak Jain, SPE, Raymond Tibbles, SPE, and Joc Abstract Cased-hole gravel packing is commonly J. S. Andrews, SPE, H. Bj�rkesett, SPE, J. Djurhuus, StatoilHydro; I. C Abstract Gj�a is an oil and gas field located off S. Wibawa, S. Kvernstuen, Schlumberger, and A. Chechin, J. Graham, and Abstract This paper presents the first installation M.R. Wise and R.J. Armentor, Chevron, R.A. Holicek, B.R. Gadiyar, M.D. Abstract Screenless sand control completions pro B. Vidick, SPE, S. James, SPE, and B. Drochon, SPE, Schlumberger Abstract The search for a cost-effective alternativ

K. Qiu, SPE, Schlumberger; Y. Gherryo and M. Shatwan, SPE, AGOCO, LibyAbstract Sand production from the Sarir field beca K. Qiu, J.R. Marsden, J. Alexander, and A. Retnanto, Schlumberger, and This paper was also presented as SPE�100948 Ahmed Abulsayen and Abdulwahab Enneamy, VEBA (Libya), and Kaibin Qi Abstract This paper described a case study involv Bailin Wu, SPE, and Chee P. Tan (Now with Schlumberger Oilfield Support Summary It is commonly acknowledged in the pe Abdullah Kasim, SPE, Petronas Carigali; and Frank Wijnands, SPE, and S Summary Although the stacked reservoirs of the B J. Heiland, SPE, and M.E. Flor, Schlumberger Abstract During production of hydrocarbons the B. Wu, SPE, CSIRO Petroleum; Nulwhoffal Arselan Mohamed, SPE, Petronas Abstract This paper presents a geomechanical st Hisham A. Nasr-El-Din, SPE, Saudi Aramco, and Mathew Samuel, SPE, SchSummary Viscoelastic surfactant systems are use M. Pournik, C. Zou, C. Malagon Nieto, M.G. Melendez, D. Zhu, and A.D. Hi Abstract The effects of acid solutions injected into G. Zaeff and C. Sievert, SPE, ConocoPhillips, and O. Bustos, SPE, A. Galt Abstract The goal of an acid fracture treatment is J. Ricardo Solares, SPE, J.J. Duenas, SPE, Moataz Al-Harbi, SPE, Abdul Abstract Acid fracturing has been an integral part J. Ricardo Solares, SPE, Moataz Al-Harbi, SPE, Abdulaziz Al-Sagr, SPE Abstract Acid fracturing has been an integral part M.A.P. Albuquerque, SPE, Schlumberger; A.G. Ledergerber, SPE, Chevron; Abstract Between December 2003 and February B. Lungwitz, SPE, Schlumberger; R. Hathcock, SPE, K. Koerner, SPE, D. Byr Abstract The Maca� formation (Cretaceous ag Hai Liu, SPE, Chad Coston, and Mohamed Yassin, SPE, Schlumberger; ShaSummary Effective matrix acidizing in Kuwait’ Yin-Chong Yong and Karim Saaikh, Brunei Shell Petroleum; Joao Queiros Abstract Improving oil and gas production from th H.A. Nasr-El-Din, SPE, and M. Zabihi, SPE, Saudi Aramco, and S.K. Kelka Abstract In treating sour water injectors in carbon R. Arangath, SPE, Schlumberger; K.W. Hopkins, Aral Petroleum Capital; D Abstract Stimulation of carbonate reservoirs is ofte F.F. Chang, SPE, Schlumberger; H.A. Nasr-El-Din, SPE, Texas A&M UniversiAbstract Hydrochloric acid is the most commonly u Surajit Haldar, SPE, Ahmed A. Al-Jandal, SPE, Saad M. Al-Driweesh, Mufe Abstract The Uthmaniyah field is one of the bigges Rafael Rozo, SPE, and Javier Paez, Petrominerales; Alberto Mendoza, SPEAbstract The Caballos formation is thick laminate Rafael Rozo and Javier Paez, Petrominerales; Alberto Mendoza, Ecopetrol; Abstract The Orito field in the south of Colombia w Frank F. Chang and Xiangdong Qiu, Schlumberger, and Hisham A. Nasr-El- Abstract The purpose of matrix treatments in carb D. Oussoltsev, I. Fomin, K.K. Butula, and K. Mullen, SPE, Schlumberger, andAbstract The majority of oil exploited from Russia Murtaza Ziauddin, SPE, and Emmanuel Bize, SPE, Schlumberger Abstract Most carbonate reservoirs are heterogen L.P. Moore, SPE, and H. Ramakrishnan, SPE, Schlumberger Abstract Restimulation of existing wells represents O. Bustos, Y. Chen, M. Stewart, K. Heiken, and T. Bui, Schlumberger, and P Abstract CO2 based fluids are commonly used to K. Hughes and N. Santos, SPE, Chevron, and R.E. Arias and S.V. Nadezhd Abstract Historically carbon dioxide (CO2)–foa S.A. Utegalyev and S.K. Duzbayev, KazMunaiGas RD, and K. Kulbatyrov a Abstract Well stimulation techniques like hydrau Mohan K.R. Panga and�Suzylawati Ismail, Schlumberger Well Services; Abstract Water blocks and condensate drop out n Majdi Al Mutawa, Bader Al Matar, SPE, and Abdulaziz Abdulla Dashti, SP Abstract Dual completed wells producing from the Douglas Boyd, Salah Al-Kubti, Osama Hamdy Khedr, Naeem Khan, and KholAbstract Two classes (sonic and ultrasonic) of cem N.M.A. Rahman, SPE, Schlumberger, and M.S. Santo and L. Mattar, SPE, FAbstract A new technique for analyzing and model A.K. Ambastha, SPE, and M. Anderson, SPE, Chevron Corp.; H. Gandhi, SPE Abstract Mauddud reservoir in the Greater Burgan J.F. Manrique, Occidental Oil and Gas Corporation, and B.D. Poe Jr., Schl Abstract We present a unique methodology desig Moustafa Eissa, Sameer Joshi, and Kamaljeet Singh, SPE, Schlumberger Abstract Conventional pressure transient testing u K. Slimani, Sonatrach; D. Tiab, U. of Oklahoma; and K. Moncada, SchlumbeAbstract Often and for many reasons the wellbore Fikri J. Kuchuk, SPE, Schlumberger Abstract Although it is often used in pressure tran C. Contreras, SPE, S. Bodwadkar, SPE, and A. Kosmala, SPE, SchlumbergAbstract Reservoir engineers operating in mature M. Onur, SPE, and M. Cinar,* SPE, Istanbul Technical University; D. Ilk, Summary In this work we present an investigatio A.J.G. Carnegie, Schlumberger; Stephen Ball, Premier Oil Vietnam; Pierre Abstract T Two Case Studies Hassan Bahrami, Sharif University of Technology; Jamal Siavoshi, Husky Abstract The identification of fractures is essential S. Daungkaew, J.H. Harfoushian, and B. Cheong, Schlumberger; and O. Akins Abstract Exploration and appraisal campaigns for N.Karthik Kumar, SPE, Sameer Joshi, SPE and Raj Banerjee, SPE, Schl Abstract This paper presents techniques for interp David Costa; Total ABK, Jean-Paul Couput, Total; Florian Hollaender, Bru Abstract Flow metering using conventional separa B. Theuveny, Schlumberger; I.A. Zinchenko, Yamburggazdobycha Gazprom Abstract A number of tests were performed in Yam E.J. Pinilla, SPE, C.H. Pardo, SPE, L.M. Warlick, SPE, and Y.M. Al-Shoba Abstract Well testing is one of the most effective m Kelechi Isaac Ojukwu, Petroleum Development Oman, and John Edwards, Abstract The use of multiphase flowmeters (MPF B. Theuveny, Y. Shumakov, and A. Zhandin, Schlumberger, and I. Zinchen Abstract Surface welltesting of Gas-Condensate w D.I. Atkinson, Schlumberger Cambridge Research; �. Reksten, 3-Phase Summary Dedicated wet-gas flowmeters are now M. Metwalli Hassan and M. Bekkoucha, ADCO, and M. Abukhader, SchlumbAbstract Production testing using portable Multiph

B.G. Pinguet, G. Roux, and N. Hopman, Schlumberger Abstract Faisal M. Al-Thawad, SPE, and Jim S. Liu, SPE, Saudi Aramco, and Raj B Abstract D. Ilk, N. Hosseinpour-Zonoozi, S. Amini, and T.A. Blasingame, Texas A&M Abstract A.F. Veneruso, SPE, and J. Spath, SPE, Schlumberger Abstract M.-Y. Chen, B. Raghuraman, SPE, I. Bryant, SPE, and M. Supp, Schlumber Abstract

Using multiphase flowmeters in field ope The objective of this study was to investi In this work we present the application o The pressure derivative has become the Two successful field tests of streaming p

cal storage is about pumping a reactive fluid underground and ensuring it doesn't find a way back to the atmosphere for a very long time †an estimation of the full stress state between 0.5 and 2.1 km depth at the Otway CO2 storage pilot site Australia where the Cooperative R major challenges associated with CO2 geological storage is the performance of the confining system over long timescales. In particular the on of greenhouse gas emissions in order to decelerate the global warming process could be achieved through the emerging process of geo r CO2 emissions reduction at a large scale globally implies that CO2 injection into the subsurface be undertaken in a greater variety of geo of carbon dioxide (CO2) in saline aquifers is one of the most promising options for Europe to reduce emissions of greenhouse gases from p ired plants are responsible for the one third of the carbon dioxide (CO2) emissions which thought to be a major contributor to the current r he trapping of CO2 in the subsurface i.e. storage containment is of fundamental importance for a safe geological storage of carbon dioxide ide capture and storage (CCS) is emerging as a key technology for greenhouse gas (GHG) mitigation. The Society of Petroleum Engineers ¢ is a set of production data standards initiated by 13 upstream oil and service companies with the industry standards body Energistics (the /8-A-6 AHT2 was drilled from the Visund Field Floating Production and Drilling Unit (FPDU) in the North Sea and set on production in Octo rton Field operated by Maersk Oil North Sea in Block 15/20 has a number of drilling and well placement challenges which hampered deve Qatar AS (MOQ) completed drilling the world record BD-04A well in May 2008 offshore Qatar. This was the successful outcome of engineeri Formation historically known as the Brown Niagaran is a Silurian age formation in the Michigan Basin containing hundreds of pinnacle ree on is one of the most efficient methods used to improve oil recovery and as world statistics shows its use has increased recently. Under a ene Vicksburg formation in South Texas has been a prolific play for many years with targets of thick and stacked sand bodies. These thick nsate reservoirs usually exhibit complex flow behavior due to the near-wellbore condensate bank build-up when bottomhole pressure drops esented in this paper describes the evaluation and stepwise optimization process for a Steam-Assisted Gravity Drainage (SAGD) project us iscusses the gas shut-off treatments carried out in a fractured carbonate field in north Oman and also describes the good practices and less g is a mature field with 8 rounds of field development campaigns and close to 40 years of production. Currently only 50% of total strings are n from some of wells in the White Tiger field producing from a fissured Basement reservoir; have been impaired by excessive water produc wells in Sabriya Field (Northern Kuwait) produce from reservoirs where multiple layers are opened to production. Problems related to non-d tacked nature of reservoirs in the Niger Delta the predominant completion types are dual-string multizone and single-string multi-zone comp off treatment (WSOT) using through tubing bridge plug (TTBP) in open hole completion has been employed for the first time in a dead horiz covery of new fields becoming less common and the continued development of brownfields water control is becoming increasingly essentia uction is a major problem for any oil and gas field. If not properly managed unwanted water production will seriously impact the economics ol is the key to prolong well life for economical and efficient oil recovery. When water reaches certain levels oil production profitability decre arge potential reserves increased global demand for oil and high oil price exploration & development in deepwater and more challenging a mic characteristics of oil/water flow systems have not been understood fully. The need for improved designing methods has led researchers ow is a common occurrence during production and transportation of petroleum fluids through pipes. Understanding of oil/water pipe flow be tion of intelligent wells to improve the economics of production is now common practice.�These wells allow the access to marginal reser in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their er production systems extreme pressure and temperature conditions multipart sub-sea networks complex reservoir characteristics and va nt of deep offshore fields is costly. As such accurate information is required before a decision can be made on the feasibility of prospect de ide (CO2) occurrence in hydrocarbon bearing formations presents a challenge to the valuation and subsequent prospect development of th t uncertainty in establishing reservoir connectivity has always been an issue for reservoir management. Standard correlation methods using precipitation can have profound effects on oil production during miscible flooding heavy oil recovery or even primary depletion. Even thoug d properties are required for studies related to management of gas/condensate reservoirs or prediction of condensate reserves. Often thes hors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. It was show large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir h cation is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Kal cterization quantifies the reservoir phase behavior fluid compositional changes throughout the reservoir and changes in fluid properties as characterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages o based mud (OBM) filtrate contamination poses a major challenge to the acquisition of representative fluid samples using wireline formation escribes a new Downhole Fluid Analysis technology (DFA) being implemented in Latin America for improved reservoir management. DFA is Case Studies mation testing provides formation pressures high quality samples and fluid identification/characterization. In addition it can provide informa opment projects will rely on producing through existing production facilities which may not have been designed for sour hydrogen sulphide

uids frequently reveal complexities in hydrocarbon columns. Fluid compositional grading is usually caused by gravitational forces thermal g and analysis of gas/condensate-fluid samples presents considerable challenges. This is because downhole sampling of a gas/condensate ompartmentalization quantifying connectivity and assessing the presence of compositional grading are critically important to reservoir man uid identification plays a crucial role in reservoir characterization and hydrocarbon volume estimation. Gas condensate reservoir is well know presents a case study of a North Sea appraisal well in which a vertical fluid-composition variation missed by a conventional pressure-grad epth plots have been used for over thirty years to evaluate fluid density fluid contacts and pressure compartmentalization in formation teste uids often show complex compositional behaviors in single columns in equilibrium due to combinations of gravity capillary and chemical for fluid sampling early in the life of a well ensures that vital information is available for timely input to field planning decisions. For example in escribes the study of the effect of asphaltene precipitation and deposition on the development of the Marrat field using a compositional sim uid analysis (DFA) together with wireline formation testing tools provides real-time measurements of reservoir fluid properties such as comp nts are common in gas condensate and volatile oil reservoirs but they are also present in heavy oils reservoirs. There are numerous public ears formation-sampling and formation-testing tools have provided a variety of new downhole optical measurements for downhole fluid ana aracterization and asset management require comprehensive information about formation fluids. Obtaining this information at all stages of sters are commonly used to obtain fluid samples and measure formation pressure during openhole logging operations. Accurate identificati describes in detail computational techniques and formulations for constructing a phase envelope and/or subsequent isenthalpic/isothermal f variably produced with crude oil. If there is enough shear force when crude oil and produced water flow through the production path stable ve reservoir fluid sampling & characterization has become increasingly important as the exploration activities are moving into the ever-chal neration of wireline formation testing fluid analyzer presented in this paper integrates in-situ optical fluid analysis device with a oscillating me density-viscosity (D-V) sensor is introduced that provides a real time direct measurement of in-situ density and viscosity at reservoir conditi eous carbonate reservoir can be partly evaluated using OH logs but not fully. Even if production testing is used for evaluation important det eration of sampling technology is introduced that allows a wireline formation tester (WFT) to sample reservoir fluids in open hole with levels ssure testers and reservoir fluid sampling tools have for quite some time now been considered viable alternatives to well testing. These to tive reservoir fluid sampling and characterization has become increasingly important over the years. With exploration appraisal and develop well testing has been acknowledged worldwide as a state-of-the-art technology for metering stream of oil gas and water without prior phase ion of deep wells is a difficult task mainly because of high reaction rate and the high corrosion rate induced by strong acids. One way to ad cally complex Algyo field discovered in 1965 is the largest hydrocarbon occurrence in Hungary consisting of more than 40 oil-and-gas-bea matrix acidizing fluids for sandstone are executed in the field only after core tests qualify their ability to remove damage. However most core nvestigates the application of halite inhibitors and the mechanisms associated with salt formation and inhibition. Several new chemistries (tw mation damage with waterflooding using sea/produced water has been widely reported in the North Sea the Gulf of Mexico and the Campo ate-soap deposition and the related formation damage in petroleum reservoirs are investigated by means of laboratory-scale experimental a rge perforating subjects the formation to shock-loading and large impact stresses causing damage to the rock surrounding the perforation t ompletions perforations provide the essential link between the wellbore and the reservoir. Productivity of the completion is promoted by op ated to inorganic scale precipitation are common in oil fields across Russia. The predominantly calcium carbonate scale rapidly precipitates ation and accumulation of scale deposits is a major concern for production companies in the Uinta Basin. Since 2003 conventional hydrauli hallenge facing the oil industry is to reduce development costs while accelerating recovery while maximising reserves. One of the key enab ition in completion strings is becoming a threatening problem to produce and safely operate wells completed in the Upper ZAKUM (UZ) oil f m stripping is commonly observed in sandstone reservoirs where seawater mixes with formation water that may be rich in calcium strontiu ld history matching is generally performed first at the field level then at regional level followed by individual well history matching. This pap vancement in streamline simulation technology in modeling fractured reservoir and streamline associated well allocation factors now it can discusses the incorporation of Streamline simulation into the Reservoir Management Processes of the super giant Sabriyah oil field. For the he Gulf of Mexico Cantarell Field is the world’s second largest carbonate field which has been on production since 1979. After the imple presents the results of an automatic surveillance system implemented by PEMEX for one of Mexico’s largest gas fields.� Activo Integ ater flooding has been the preferred pressure maintenance tool for many gulf carbonate reservoirs over the past 30 years. Due to uneven s utlines the successful integration of subsurface water handling well surveillance and production operations teams across the North Kuwait onal means of artificial lift production for vertical and deviated wells in the Orinoco oil belt in eastern Venezuela used to be rod pumping and Belt (Faja) in Venezuela contains one of the largest resources of heavy and extra-heavy oil in the world. Due to the production decline of co al EOR methods like steam-injection are usually not cost effective for deep wells and wells producing from thin pay zones due to excessive Heavy Oil Belt (Faja) has been exploited under primary recovery techniques using mainly horizontal fishbone and multilateral wells. This c and development of Heavy oil fields in Muglad Basin in Northern Africa started with conventional vertical wells and as time progressed this m ne/Eocene age 1st Eocene Reservoir is the shallowest producing interval of Wafra Field in the Partitioned Neutral Zone (PNZ) Saudi Arabi mation testers provide the measurements for the determination of formation pressure gradient in-situ effective oil mobility profile in-situ dow

avy oil field located in Muglad basin in Sudan. Aradeiba reservoir in the field consists of highly heterogeneous sandstone that is thinly bedde

ormation in the Gulf of Suez is highly fractured depleted reservoir producing 9 to 10 API gravity heavy oil at water cuts up to 98%. Stimulat nment With Sand Screen: A Case Study From Kuwait ecent hydrocarbon discoveries in the Gulf of Mexico are heavy and extra-heavy oils. Additionally given the imminent decline of lighter crude e is to present accurately the performance of the combination of a venturi and multi energy gamma ray in a case study in Venezuela. The fo bitumen produced by Steam-Assisted Gravity Drainage (SAGD) induces many issues arising from high operating temperatures (150-200 C cidizing is very challenging because of the complex reactions that occur between the multiple-stage treatment fluids and the formation mine nd fluids evaluation of heterogeneous and over pressured retrograde gas condensate low-permeability but high-reserves potential reservoir has already been undertaken by various operators throughout the industry to explore frontier areas and drill into ever-deeper geological hor ies descriptions are required for the design and implementation of petroleum production processes. Increasing numbers of deep water and of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment.� In certai of crosslinking a polymeric fracturing gel can significantly contribute to the success or failure of a hydraulic fracturing treatment.� In certai ng is the commonly applied stimulation technique in low permeability carbonate reservoirs. Achieving adequate fracture length is challengin Temperature Environment in Mexico Marine describes an innovative and reliable first� High Pressure High Temperature digital electric permanent monitoring solution with state-of-the resents the results of propped fracturing operations conducted in the past 12 years in the Bach Ho (White Tiger) field offshore Vietnam. Hig n an oil field in East Venezuela have a bottomhole static temperature of approximately 230�F and varied mineralogical composition from ed on chelating agents have been developed for matrix stimulation of high-temperature sandstone formations. These fluids dissolve sizeabl ge Basin is characterized by multilayer formations requiring proppant fracturing as a completion method in order to achieve oil production at presents the development of a chemical system for water-block prevention in gas/condensate wells. The chemical system alters the forma describes a new technique for measuring pH on live formation water samples in the laboratory at high temperature and pressure. The techn tion and deposition of asphaltenic material in reservoir rock are significant problems in the oil industry and can adversely affect the producib describes an efficient multistage horizontal openhole completion technique as an alternative to conventional openhole or cemented and per ity Carbonates and rises and operators turn to tight gas reservoirs for new supplies the need to optimize the capacity and recovery potential from this type ntional tight gas reservoirs are made economical through effective stimulation techniques. Hydraulic fracture mapping combined with an incture azimuthal orientation depends on stress distribution in the formation and is considered to coincide with the maximal horizontal stress nt of gas are being produced from unconventional tight-gas sand reservoirs (e.g. Cotton Valley Fm. Lobo Fm. Taylor Sand Fm. and Wilco acture treatments are necessary to ensure the best deliverability of tight gas from east Texas Cotton Valley Sands.� Historically these trea ity Tight Gas Formations s Limestone in South Texas often requires stimulation to be commercially productive. The relatively low permeability high Young’s Mod past decade multiple transverse fracturing in horizontal wells has been applied so successfully in onshore low-permeability reservoirs that it as field in Sichuan Province whose discovery was officially announced by CNPC in August 2005 is a large-scale gas reservoir that has in e Oolite carbonate reservoir in the Partitioned Neutral Zone (PNZ) is located between Kuwait and Saudi Arabia and has been a prolific oil prod presents a closed-loop reservoir study in tight gas fluvial sands of the giant Jonah gas field located in the northwestern part of the Greater G r we will present an integrated single well modeling (SWM) technique to predict reservoir and completion performance for a Uinta basin dev presents several workflows for constructing adequate flow models of a tight gas field located in Wyoming. The numerical flow models were nated tight gas sand sequences remain prolific targets worldwide and have often been bypassed using standard petrophysical analysis and Grained Sandstones natural fractures in tight carbonate reservoirs during the exploration and early development stages is critical in order to reduce geological un mation testing in low permeability carbonate reservoirs of the UAE has been challenging with frequent tool plugging extended pumping time the world’s oil and gas reserves are locked in tight “unconventional reservoirs. Without the presence of fractures (natural or hydra covery in tight gas reservoirs typically mandates infill drilling programs. Characterization of reservoir pressure depletion and sand body cont covery in tight gas reservoirs typically mandates infill drilling programs. Characterization of reservoir pressure depletion and sand body cont vided by wireline formation testers (WFT) is critical to the evaluation and understanding of petroleum reservoirs. Pretest pressures gradien presents a field-development case study of a low-permeability turbidite reservoir in Russia. The giant Priobskoye field contains 30�API c successful applications of horizontal wells have been limited to high-permeability reservoirs and unconventional formations such as coal c -Takhomskaya oil and gas accumulation zone (YTZ) located in the western part of the Siberian platform is known as a really challenging ex declining production and increasing demand geoscientists are challenged more and more often to develop new techniques and strategies al of tight sands (quartzitic sandstones) makes these non-conventional reservoirs a priority for oil companies during next decades. Due to nu

onate reservoirs several factors make it difficult to estimate reserves in transition zones. In particular underestimation of reserves sometime uction from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells leading to a co n of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts imple resents a case history of a slickline propellant stimulation treatment performed in a well at the Penara and North Lukut field which is a sma aking within the petroleum industry is a complex process involving extensive analysis of multiple objectives based on a variety of diverse crit aking related to oil and gas exploration and production relies on objective data analysis as well on subjective judgment of experts. Expert jud e of supplying real time LWD or FE information (Logging While Drilling and Formation Evaluation) should be to enable the client to make qu essure curves are a fundamental input to reservoir simulators both from the standpoint of initializing fluid saturations and from the perspecti hole logs formation testers pressure transient tests and production logs are usually used to assess reservoir heterogeneity. A common lim s based on conventional logs are found as strongly correlated to core lithofacies thin section microfacies and petrophysical measurements the depositional sedimentary environment is the most important task for exploration geologists to model the reservoir heterogeneities. Inte reservoirs of the eastern Sahara province represent one of the main oil and gas accumulations in Algeria. This clastic succession correspon fluid analysis (DFA) has emerged as a key technique for characterizing the distribution of reservoir-fluid properties and determining zonal co cation is an important objective to resolve key uncertainties of a complex reservoir prior to perforation in the developed fields of Eastern Ka ysical evaluation of carbonate reservoirs in terms of predicting the hydrocarbon potential is trivial. However it is difficult to correctly predict ipam sandstone reservoir of Miocene age in the Jaipur oilfield lies within a highly folded and faulted Assam-Shelf basin in the north eastern ging-while-drilling (LWD) tool that combines traditional measurements of gamma ray propagation resistivity gamma-gamma density and th e chemical logging sources have been used in the E&P industry for many years to help operators obtain valuable information about their re erns have been expressed regarding discrepancies between LWD (Logging-While-Drilling) and WL (Wireline) GR (natural gamma ray) resp the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and hence fying the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and h op concerns for carbonate reservoir evaluation is the effect of rock texture on permeability capillary pressure and relative permeability. Rece ir is composed of a mixture of dolomite limestone anhydrite and shale interstratified with sandstones member. The sandstone is predomin udy demonstrates a new method to compute continuous permeability and estimate reservoir rock type from logs in a complex heterogeneo urbidite reservoirs are composed of interbedded porous and permeable sands with variable proportions of thin silt and clay beds.� These he perforation intervals and evaluating the productivity of thin-bedded sands and shales is crucial for well completion cost optimization. This physical Analysis valuation in thin sand-shale lamination seeks first to determine sand resistivity volume fraction and porosity. Afterwards saturation and volu on evaluation (FE) of horizontal injectors drilled in water swept reservoirs involves different physical understanding of log responses to fluid ical viability of the Cambrian sandstone reservoirs in the Hassi Messaoud field is closely linked to the presence of fractures. Natural or hydr mation testing (WFT) and fluid sampling has long been used for determination of reservoir pressure evaluation of fluid type from in-situ den erest in fractures and faults in a giant carbonate oilfield offshore Abu Dhabi involves such aspects as their origin nature orientation and im trapping mechanism plays a critical role for hydrocarbon entrapment within the Middle-Late Cretaceous reservoirs in the Al-Khafji area. 3D Model was built and an Uncertainty Assessment approach was used to better understand the reservoir behaviour. Conceptual models were of spatial statistics geostatistics is commonly used to model geologic facies and petrophysical properties. The spatial characteristics of geo ed reservoirs are increasingly a target of offshore exploration in the Malay Basin. These reservoirs exhibit heterolithic interbedding with verti lear magnetic resonance (NMR) logging to help with the petrophysical evaluation of thin sand-shale laminations. NMR helps to 1) detect thi al power scenario changes with increased demand for oil and gas remote and challenging (deepwater offshore high pressure-high temper illustrates the improvements in logging while drilling (LWD) images and subsequent formation evaluation by using a new methodology for d Burgan Field consists of three sub fields (Ahmadi Burgan and Magwa). Drilling commenced in this field in 1938 and it went on stream in 1 on and injection of fluids in a reservoir results in reorientation of stresses. This phenomenon has been supported by field studies and micro anical parameters of reservoir rocks play an extremely important role in solving problems related to almost all operations in oil or gas produc leted reservoirs exhibit sharply lower pore pressures and horizontal stress magnitudes than does the overlying shaly formation. Drilling thro presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliv presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliv presents the results of an investigation concerning the development of a reliable and accurate technique for establishing the stabilized deliv ah Sargelu and Marrat reservoirs are the main Jurassic reservoirs in Kuwait. These fractured-carbonate reservoirs that have moderate-to-lo ate reservoirs in Gulf of Suez area have complex geological structure due to the existence of fractures associated with faults. Thus fracture ocated in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial ing Upper Jurassic Arab reservoirs of an offshore Abu Dhabi fractured carbonate field (Abu Al Bukhoosh) have been producing for more tha hskoe field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin wher

we present a novel method for in situ estimation of two-phase transport properties of porous media using time-lapse resistivity pressure a s of defining the fluid and reservoir properties of a hydrocarbon discovery represents a significant challenge to the industry. The practice of p rmation Tester (WFT) pretest success ratio (good versus tight pressure points) has been traditionally low in East Kalimantan-Indonesia over asurements have long been used to evaluate rock properties in the near-wellbore region and these methods are well documented. Compre idated with superior results that the direct measurement of porosity using Nuclear Magnetic Resonance (NMR) in Naturally Fractured Clast most important objectives of fluid sampling using wireline formation testers (WFT) is to ensure that representative samples of the different flu s of shaly sand gas reservoirs with low and variable formation water salinity presents specific challenges. These formations usually exhibit lo challenge for nuclear magnetic resonance (NMR) well logging is that the quality and utility of the data depend on the acquisition sequence Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent de ifferent petrophysical methodologies have been developed to improve the success rate in selecting oil intervals in the Gulf of San Jorge Ba many of the producers are horizontal wells and a considerable number of them are equipped with smart complex completions. Evaluating the odology for porosity and permeability analysis in Carbonates with Inter-granular and Macro porosity is presented. This methodology uses NM nced drilling (UBD) is defined as a drilling operation in which the pressure of the circulating drilling fluid is lower than the pore pressure of th h structure in southwest corner of Kuwait is a multi reservoir field. One of the potential reservoirs is the Mishrif formation. Developed as a lim compartmentalization and understanding reservoir structure are of critical importance to reservoir development. Traditional methods of iden ng reservoir architecture is critically important to effective reservoir management. Misinterpreting reservoir compartmentalization for instan ntalization is perhaps the single biggest risk factor in deepwater petroleum production. Downhole fluid analysis (DFA) is a new tool to reduce resents the results of an investigation involving the development of a reliable and accurate methodology for establishing the stabilized deliv estimations are mainly based on special analysis of representative core samples (SCAL). In high recovery oil fields where remaining oil sat entary features of gas fields are multilayered deltaic thinly laminated shaly sandstones consisting of channel and bar sands with limited la hofacies Mapping management requires the optimization of hydraulic fracture placement. The lack of direct stress measurements (vertical distribution and dire n of pressure transient tests conducted in a dynamic environment like drilling is challenging. One of the difficulties arises due to phenomen eld Development Plan (FDP) for Betty Field was prepared based on a process that was simultaneously sensitive to reservoir and operationa challenges that operating companies face during any oil field development project is to deal with the uncertainty associated with the data ac on declines and watercut increases wells are often converted from gas lift to electrical submersible pumps (ESPs).� ESPs are an attract ew life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has dwide production surveillance for artificial lift is critical in brown field operations to ensure optimum field production and efficiency. Using app a is blessed with the world’s largest onshore and offshore reservoirs. Currently Saudi Aramco is aggressively pursuing production increm in sand bodies while drilling across heterogeneous sandstone reservoir is a major challenge that requires integrated reservoir engineering from low-pressure gas wells was improved by widespread/extensive installation of well site compression in the Waddell Ranch Project. The kflow methodology that covers the entire cycle of field development maximizes the production potential and can increase reserves in stacke anagement is a standard industry practice to maximize oil recovery; however in mature fields the full potential is often not realized. Unlike g w alternatives to develop and produce sands B1 and B4 together belonging to the reservoir VLG-3729 of Moporo Field located in western gement (FM) is the simulation workflow through which predictive scenarios are carried out to assist in field development plans surface facili most common methods of increasing production in oil fields is through the continuous injection of lift gas into the tubing.� The injected gas simulation model calibrated with 25 years of production history was used to determine a cost effective reservoir management and productio oil field discovered in 1968 and produced since 1978. With the objective of rejuvenating the asset a multidisciplinary optimization team was tion projects consume considerable amounts of energy to generate steam.�� Understanding where the heat goes at various times and servoir studies aim at synergizing all disciplines to form a reservoir understanding and best strategy to field development. Handling uncerta e of this paper is to highlight the necessary steps for the successful use of integrated asset modeling. It presents the full workflow for optim technology from reservoir through process facility has advanced so much that field development strategies can be developed within a new in the upstream business operational decisions are made separately at the reservoir production and surface facility levels using only their rocessor cluster computing modular stochastic workflows and a dedicated project team the turn-around time for project execution has bee ational Offshore Oil Corporation (CNOOC) Shell and ConocoPhillips China Inc. (COPC) are partners in the development of the XJG oil fi on of large volumes of water is common in wells producing from strong aquifer reservoirs such as most of the fields in the Oriente basin of t by limited capacity of 25 MMSCF/D was introduced for Khafji field in 1988 which could successfully sustain target rate until mid of 2004. A 6S and 3S oil fields in the Pearl River Basin Offshore South China Sea are mature fields which have produced 40% to 60% of their origina will illustrate the collaborative approach taken by an integrated team (operator and service company) charged to demonstrate within a one presents a unique workflow for gas reserves evaluation in fields with commingled production from several low permeability reservoirs. The w of high demand for rigs and other scarce equipment it may be appropriate and more advantageous for a client to agree to a forward contr

t describes how advanced well placement technology helped to optimize horizontal well position and maximize hydrocarbon production in d exco North Sea Limited developed the Brenda field in the Central North Sea. A total of over 8000 ft of horizontal section has been drilled in a methodology of converting standard reservoir models to maps of production potential for screening regions that are most favorable for we ment decisions are routinely made on the basis of simulation models that are created before production operations begin. Real-time downh presents an innovative filtering and analysis approach to identify candidates for sidetracking in mature water flooded fields.� It targets byp infill drilling in oil rim reservoirs is a challenging task. In the case of thin oil rims with large gas caps early gas breakthrough and gas cycling ng the optimal location of wells with the aid of an automated search method can significantly increase a project’s net present value (NPV mber (SC) control during steam-assisted gravity drainage (SAGD) has a great impact on the efficiency of heavy oil and natural bitumen reco t a set of new analytical solutions to the single layer reservoir problem both in real time and Laplace space.�The solutions are derived a new semi-analytical solutions to the multiple layer reservoir problem both in real-time and Laplace space. Assuming a vertically stacked sys g geologic models to production data is generally done in a Bayesian framework. The commonly used Bayesian formulation and its impleme hod-based sensitivity for field-scale history matching with large number of parameters suffers from several limitations. First the CPU time de bjective is to investigate the use of Artificial Intelligence (AI) methods to accelerate the history matching process. A new criterion for measu reasing acceptance of stochastic workflows in mainstream reservoir engineering studies many frameworks have been developed to assist presents a novel methodology of history matching using the face recognition technique based on Principal Component Analysis which is cu Permeability e the construction of a general unstructured grid parallel fully-implicit simulator for complex physics associated with heavy oil thermal recov describes a general formulation for phase-component partitioning that can accommodate any number of phases and components any com wells often present a substantial challenge in reservoir simulation. In a recent field review we experienced difficulties modeling long horizont

nd multi-lateral wells have become increasingly important and represent a growing percentage of production wells. They are used to maxim tion of Complex Wells (CW) as a component of an optimized field development strategy at single well sector model and or small scale mult essure stress state and geological structures as well as their evolution during an oil/gas field life have widespread influence on implications -compositional reservoir simulator pressures saturations temperature and compositions in all the existing phases must be solved. When t ve analysis is a graphical procedure used for analyzing declining production rates and forecasting future performance of oil and gas wells. T re-propagation process performed with polymer-based fracturing fluids is applied commonly to increase the productivity of producing wells he substantial tight-gas resources worldwide hydraulic fracturing is for many cases economically a viable option. However despite the sta wells with multiple fractures are becoming more prevalent in the Industry. They are especially beneficial in carbonate plays where acid and fr te reservoir simulation is required to better describe multiphase fluids flow to hydraulic fractured wells and improve the development of gasp is one of the mechanisms that can alter the growth of a hydraulic fracture when it encounters weak planes or natural fractures. In shallow presents explicit simulation of hydraulic fractures in horizontal wells to predict the fracture behaviour and post-fracture production profile le ow reduces the productivity of fractured and frac and pack wells and causes erroneous results if ignored when analyzing well test data.1 Cu t gas reservoirs are often completed with multiple stages of hydraulic fracturing. Eventually each stage contributes to the commingled well p presents the results of an investigation concerning the development of more accurate predictive and interpretive models of the boundary-do on of horizontal well technology over the last twenty years has led to the parallel increase of the number of hydraulic fracturing treatments in this paper is to investigate the near-wellbore phenomena with respect to fracture initiation. The 2D numerical model was developed which eural networks (ANNs) have been used widely for prediction and classification problems. In particular many methods for building ANNs hav ture reservoir performance and uncertainties associated a series of reservoir simulation runs are required. It is now a common practice to g rs in the Nile Delta of Egypt are characterized vertically by its thin beds of sands and shale and laterally by severe variations in facies. Thes presents a mathematical model describing the variation of temperature along the length of a horizontal well during the process of water inje es of about 2 cP and above (under downhole conditions) are common and often exhibit poor end-point mobility ratios when displaced by wa r we present the results of a material balance study for a mature field in East Malaysia. The field consists of several stacked sands and is h n Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is ava n objective of the mature fields development optimization is the value adding through extension of field life. While elaborating field developm nt formulation and numerical solution of two-phase multicomponent diffusion and natural convection in porous media. Thermal diffusion pre arth of easy oil in the industry the importance of consistency in quantifying uncertainties and assessing their impact on investment decision y-saturation function plays an important role in describing fluid distribution and modeling flow in reservoir simulation. In our full field review nvestigates the control volume method with multipoint flux approximation (MPFA) applied to the discetization of –div(K(x)grad u) = f(x) the ities of retrograde condensation in the near wellbore region in naturally fractured formation were studied with the use of dual-porosity/dual p ce of vugs in a naturally fractured reservoir can be a significant source of reserves.� These vugs can be connected to the fracture system ation of elastic stress simulation for fracture modeling provides a more realistic description of fracture distribution than conventional statistic

uwait Jurassic Complex consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate formatio methods as a reservoir simulation tool have generated a great deal of interest in petroleum engineering because of the capability to calculat ctured reservoirs can be seen as a set of low permeability matrix rock blocks and a high permeability network of fracture channels. This rep reservoir characterization and modeling have given the industry improved ability to build detailed geological models of petroleum reservoirs models are used to solve specific problems in selected sectors of reservoirs; study production mechanisms; understand behavior of a partic nown PUNQ-S3 reservoir model represents a synthetic problem which was formulated to test the ability of various methods and research gr els are becoming more widely used as they can simplify highly complex processes with reasonable accuracy. Especially in risk analysis wh ales precipitate in oilfield systems - downhole in the reservoir in the production flow tubing and in surface facilities - because of thermodyn ng complexities of newly discovered reservoirs coupled with the increasing cost structure of field development mandate significantly improve with conventional vertical wells results in poor vertical sweep efficiency and steam breakthroughs when it is applied to heavy oil reservoirs.ï methods have become an efficient technology for reservoir simulation. The key assumption of the method is that the pressure field can be u most challenging problems for reservoir simulation is the computation of a multicomponent flow of compressible fluids in porous media with m discusses a new workflow to stochastically estimate the performance of infill locations in a mature oil or gas field. Usually performance evalu he ensemble Kalman Filter (EnKF) has gained popularity in atmospheric science for the assimilation of data and the assessment of uncerta presents a novel approach to analyze the quasi-continuous pressure data for ranking high-resolution geostatistical reservoir models and u a model for well inflow control devices (ICDs) that includes the effects of an annulus in which the flow between the ICDs is open or partially eservoir simulation still has wide application in the petroleum industry because it is far less demanding computationally than compositional s uwait Jurassic Complex (NKJC) consists of five fields each with three identified reservoirs within the naturally fractured Jurassic carbonate ock wettability is an important parameter to consider for oil recovery optimization. The great majority of sandstone formations is known to be ntal study was conducted on the mature Messla field to investigate the mechanism of fines migration and its contribution in formation dama of non-Darcy flow in hydraulically fractured wells has generated intense debates recently. One aspect of the discussion concerns the inertia carbonate oil-water transition zones contain vast amounts of producible oil. Yet traditional approaches to open-hole formation evaluation m gas field discovered in the Emirate of Dubai (U.A.E.) in 1982 was heralded as a major discovery of its time and to this day still remains stability in most of the cases is a direct reflection of earth’s in situ stress state. It is well known that the stress distribution around the w summarizes the findings of the SPE Forum held in September 2005 on “Making our Mature Fields Smarter.�Participants in the Foru e of the main oil producing country in the world with very long history of the oil industry. In one's time in former Soviet Union a lot of attention s North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access t ast 10 years several papers have been published discussing the long-term mechanical durability of the cement sheath. The customary pro han 20 years of exploitation many of the thick and prolific reservoirs of the Malay basin are depleted. However field studies indicate that la ron measurements have been used since the early 1960s to measure porosity and sigma through casing. Since the formation sigma respon e-lapse saturation information is the key to making the right decisions on completion strategy maximizing oil recovery and reducing water c st decade intelligent well completions have evolved to become engineered solutions widely used for both monobore and multilateral horizo oduction logging tool string and interpretation technique were established in order to solve the surveillance limitations in the short string sect ogging and flow profile interpretations are necessary to properly assess completion performance and interpret pressure buildup data in Cha ation of condensate banking has always been a challenge. Furthermore large productivity losses can result from the absence of early dete ation of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with for ation of low permeability oil base mud and near saturated oils presents one of the most challenging environments for fluid sampling with for describes an innovative Down Hole Permanent Monitoring System (PDHMS) that allows real-time monitoring of bottom-hole pressure and te nhole pH sensor has been developed to provide an in-situ pH measurement of formation water at reservoir conditions and results are pres ing availability of real-time downhole measurements in completions more and more uses of these data are evolving. A deepwater field in th hydraulic fracture treatment was performed on a producing well in a mature tight gas field in West Texas and induced microseismic activity ght prediction and evaluation is critical in understanding the effectiveness of a fracturing treatment. Volumetrically fracturing must adhere to gnostics of wellbore fluid entry is crucial for the understanding of well performance paramount for reservoir characterization purposes as w tart-up and early operation of horizontal steam assisted gravity drained (SAGD) wells it is important to understand the flow distribution of b addresses some recent developments in a production logging technique that uses Pulsed Neutron log measurements to evaluate the forma resents some recent developments in a production logging technique that utilizes Pulsed Neutron log measurements for the evaluation of th ystems are able to generate a temperature log along an optical fiber using a laser source and analysis of the backscattered light. This pape presents the first case study on using chemical tracers for flow profiling a subsea horizontal well with an open hole gravel pack lower comple and fluid type (phase) are two of the most fundamental parameters needed to characterize well performance. Traditional methods of estima entification is essential during exploration drilling and well completion of naturally fractured reservoirs since they have a significant impact o

lity of accurate performance information throughout the production system is fundamental to optimization of the economic potential of the re ogging low flow rate wells is difficult because mechanical spinners have a small dynamic range in slow moving fluids. Low flow rates in hori servoir has been producing for over 60 years and its pressure has slowly decreased over the years now below saturation pressure in some r we present a field example where pressure and distributed temperature measurements enabled understanding of reservoir characteristics amatic increase in oil prices oil operators are not only concerned about oil production but also they are aiming at the optimum oil productio reline formation testers (WFTs) are able to collect a massive amount of data at multiple depths thus helping to quantify changes in rock and ication of differential depletion in stacked reservoir sands before water or gas breaks through is the key to optimal reservoir drainage. How tion of microseismic and surface-deformation monitoring with an array of tiltmeters was used to monitor the warm-up phase of a steam-assi oping its Azeri field using deviated gravel-packed sand-screen completions producing from the multilayered Pereriv B C and D reservoirs. R e of subsea well intervention often leads to insufficient reservoir information for accurately understanding reservoir connectivity drainage an ey issues in creating a good reservoir model in carbonate reservoirs is the identification of the horizontal permeability conduits— “thief Dream or Reality? The Case of Remote Surveillance of ESP and Multiphase Flowmeters lity of accurate production volumes at the well level and throughout the production network is fundamental to the workflows that target the he potential of a producing well requires knowledge of the fluid types and flow rates entering the wellbore. Optimum and accurate determina resents a novel logging approach used to identify water producing zones while under-balanced drilling (UBD) horizontal wells. This approac t of oil recovery and reduction in water-cut in a matured field requires precise time lapse saturation monitoring. Behind casing resistivity an maintenance purpose peripheral wells have been used to inject sea water into a carbonate reservoir offshore Abu Dhabi. The injected wate we will briefly review the pilot design and demonstrate the utility of applying the EM imaging to the pilot. We will also show the benefit of th cross-well electromagnetic (EM) surveys are used to monitor two types of fluid injection (Water Injection and Water Alternating Gas) in a gia Coal Bed Methane (CBM) resources are huge estimated at 3 000 to 9 000 Tcf. The worldwide production from CBM is dominated by US p stems comprise the primary flow path within coal bed methane (CBM) reservoirs. These fractures also called as cleats define the reservoir raulic fracture stimulation has been one of the primary completion methods for coalbed methane wellbores for more than twenty years. How tt shale is an unconventional gas reservoir that currently extends over an estimated 54 000 sq miles. In an effort to improve well economics acturing is the requisite methodology for completing nano-darcy matrix permeability tight gas shales. Commercial success in producing thes led tubing fracturing is the predominant method for completing and stimulating dry coalbed methane (CBM) formations such as the Horses wells represent a growing percentage of the drilling activity in low permeability reservoirs within the United States.� With effective stimulat ippian Barnett Shale reservoirs have opened a new era for US gas production. Many reservoir characterization efforts have been made and 2.5 trillion barrels Canada has the world’s largest share of ultra-heavy oil and bitumen resources. While shallow heavy oil reserves are Series articles are general descriptive representations that summarize the state of the art in an area of technology by describing recent dev tion from the unconventional Barnett Shale reservoir now exceeds 3 Bcf/d which is more than 5% of total U.S. dry gas production. Typically al nature of carbonate rocks makes acidizing an effective matrix stimulation technique. Acid dissolves carbonates at high reaction rate to cre al Submersible Pump (ESP) a form of artificial lift technology has proven to be a durable solution for delivering the required rates from Sau r high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves ystems are now being considered of extreme importance as the reserves across the globe are depleting and the wells are unable to flow na hevskoye oil field development started in 1995. In 2002 by the time when all the designed vertical wells had been drilled practically all the r e northeast Brazil Manati field is located in the Camamu Bay with water depths less than 50 m. The sandstone gas reservoirs in this field ha od of completing multiple-layer formations has been successfully tested in the United States and Canada. This new method places sliding sl a mature oil field with depleted reservoir pressure supported by an aquifer in the deeper Cretaceous horizon. The Cartojani structure is loc presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells presents the results of an investigation of the design of production tubing string setting depths in gas wells to optimize gas recovery in wells servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with “good porosity.� Mat Minghuazhen is a shallow-water delta-plain sedimentary-deposit reservoir sand in Bohai Bay China. It has relatively heavy oil in place that describes a case-study detailing planning completion testing and production of the first Maximum Reservoir Contact (MRC) Multilateral (M acement efficiency in hydrocarbon formations is often caused by the natural variation in the mobility of fluids across the reservoir strata. His describes a case study that details the planning completion testing and production of the first maximum reservoir contact (MRC) multilat of multilateral gas producers drilled in the Ghawar field has significantly increased over the past few years as part of the reservoir developm ng technology is moving towards maximum reservoir contact (MRC) by means of extended-reach horizontal and multilateral wells in all type of the increasing emphasis on reducing operating costs and minimizing deferred production a new system was designed for perforating wel statistical methodology using survival analysis (SA) was developed and applied to electrical submersible pump (ESP) system performance ring has been a successful method to stimulate the Khuff Carbonate wells of Saudi Arabia since the beginning of the gas development prog eld located on the North Slope of Alaska was developed using open-hole horizontal completions drilled along the maximum principle stress

rizontal lateral Bakken dolomite play began in 1999 in eastern Montana more than 330 wells have been permitted and more than 200 wells hydraulic fracturing in various risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin as a ng has been part of Saudi Aramco’s gas development strategy to maximize productivity from for vertical wells in the Khuff carbonates o describes successful implementation of degradable fiber-laden fluids for hydraulic fracturing in one of the largest oilfield in Western Siberia. ds are usually surfactants or cosolvents added to stimulation treatments to reduce capillary pressure and water blocks. As the gas reservoirs y has been conducted on the effect of formation Young’s modulus and in situ stress on hydraulic fracture height containment in layered reservoir development continues at a record pace in North America. Additionally reservoir pressure depletion and declining quality of reserv elds produce larger quantities of water operators and service companies find themselves challenged with disposing flowback and produced he success of a tight-gas field development program in a fluvial environment is to understand the reservoir’s deliverability and what the s a pervasively used completion technique in wells targeting high permeability poorly consolidated and depleted sandstone formations locat ve pay of the low permeability Ryabchyk formation in the mature fields of Western Siberia is separated from underlying water zones by a w years horizontal well technology evolved in the Middle East field development strategies becomes favored over vertical and deviated wells scenario in many mature oilfields is to have most of the wells producing hydrocarbons with high water cuts. These wells are commonly not ca hasn’t escaped the general industry trend of finding reserves in ever challenging environments. Complex geology and low permeabil Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their key strategies in Saudi Aramco’s optimum gas development project is drilling single and multilateral wells to achieve maximum reservoir erations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment emphasis is System, Executed from a Supply Vessel; Black Sea Offshore one of ONGC’s major brownfields discovered in 1983 and located in Gujarat. The Field produces approximately 30 000 bopd and is on presents the results of an investigation of the design and analysis of the boundary-dominated flow production performance of a vertically fra despread proliferation micro-seismic fracture mapping it has been observed that some naturally fractured formations exhibit a non planar o y of hydraulic fracturing work in Russia is being done in the Western Siberian basin where operators and service companies have gathered acturing of horizontal wells in shale gas reservoirs is now an established commercially successful technique.� The evolution of the comp od of completing multiple layer wells has been successfully tested in the Piceance basin for Petrogulf Corporation. This new method placed hod of completing multiple-layer tight gas wells is being investigated. The main concept is to place sliding sleeve valves in the casing string engineers have faced the problem of hydraulic fracturing in soft rock formations for many years. However existing programs used with soft r ic Surfactant (VES) fluids are polymer-free fluids that generate viscosities suitable for fracturing operations without the use of polymer add rbon dioxide- (CO2-) emulsified viscoelastic surfactant (VES) fluid system has recently been used to improve the Olmos production in the C discusses the selection criteria design methodology and analysis of hydraulic fracturing treatments pumped using a solids-free liquid CO2 Generation Viscoelastic Fluid: Successful Case Histories in West Venezuela drilling program on North Raguba field in Libya has been suspended since the current well’s performance in this area was not promising resents the process of candidate well selection design execution and evaluation that lead to the successful implementation of acid fracturi cumented in the literature that hydraulic fracture treatments although successful often underperform: Frac and Pack completions exhibit po c hydraulic fracture monitoring is having a major impact in how wells are being completed in tight sand reservoirs.� This existing technolo mpairment in tight-gas formations is a typical phenomenon for fractured wells. Processes responsible for this behavior are related to the ch errors in the calculated azimuth and other parameters of a monitored fracture can be caused by not performing accurate borehole deviatio ity Formations fracturing treatment fracture conductivity is created by differential etching of the fracture surface by the acid; without nonuniform dissolution ization of Hydraulic fracturing in West Siberia and the increase of job size over the recent year can impact the field development strategy. T adioactive tracers have been used in combination with standard industry logging tools to gain valuable insight about the fracture height (nea f our research is on a remote oilfield in western Siberia currently in the initial stages of development. There are two producing horizons of J re are many proven ways of predicting productivity in hydraulically fractured wells in medium-permeability oil reservoirs there is still no sim s carried out to forecast the productivity of a hydraulically fractured well in a retrograde gas-condensate sandstone reservoir using a nume stribution at the tip of a hydraulic fracture is a key element for controlling fracture propagation. In low-permeability formations under downho ght carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular in-situ gell presents the results of an investigation of the design and analysis of low conductivity fractures. The mathematical model used in this work is mic imaging of a hydraulic-fracture stimulation showed significant fracture reorientation across a thrust fault. Fracture orientations were ident wback is an extremely important phenomenon in hydraulic fracturing technology and may cause severe problems for well completion. Vario the propagation of an orthogonal fracture and reopening along the initial fracture during a refracture treatment is studied by taking into acco al problem arises in enhancing oil recovery and is relevant to hydraulic fracturing process and subsequent frontal displacement of fluids from ooded reservoir hydrocarbon recovery optimization is impacted by well spacing and hydraulic fracture extent. An excessive fracture length m

summarizes part of the results of an investigation of fracture clean-up mechanisms undertaken under a Joint Industry Project active since t s a deepwater project located in Malaysia. The development plan for this field requires fifteen water injectors eighteen producers and one acturing plays a very important role in these mature and complex geology fields located onshore northeast Brazil – Carm�polis and Siri g the hydraulic fracture path have been observed in mapping of mined fractures and attempts have been made to reproduce their effects o auto natural and in-situ gas lift all refer to artificial lift systems that use gas from a gas-bearing formation to gas lift a well. The gas lift gas and Tobago (bpTT) has been developing highrate gas fields in Trinidad & Tobago since 1999 and has six high rate gas fields currently on p ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tec ompletion technology has progressed dramatically over the last six years with the latest technical barriers being eclipsed with open-hole tec horizontal wells with openhole sections or non-cemented liners is a common practice. This type of openhole wells is preferred to maximize r describes an innovative completion solutions with reservoir monitoring and control completion technologies that allows commingled oil produ wells are superior in production and recovery to conventional wells however they are subjected to early water coning towards the heel (wate ompletions have been in commercial use for over ten years. Application of intelligent completions technology has evolved from interventiondescribes an innovative completion solution with state-of-the-art reservoir monitoring and control completion technologies that allows comm hallenges remain in the development of optimized control techniques for intelligent wells particularly with respect to properly incorporating and subsequent results of a hydraulic fracturing test performed on a large block of high modulus and low permeability rock (Colton sandsto essing workflow has been engineered to combine reservoir deliverability defined by production logging (PL) measurements with nodal anal of exploration wells continue to escalate we need more than ever to evaluate each well quickly and efficiently to improve the appraisal proc blems are often observed in fields after a period of relatively smooth operation. These occurrences usually coincide with an increase in dep own that in cased-hole completions productivity is enhanced by maximizing shaped charge penetration and shot density while minimizing pe on from completion to production often requires the well to be killed immediately after perforation is completed thus exposing the formation g has been widely used worldwide to perform perforating and zonal isolation operation due to the ability in intervening highly deviated and l astern Venezuela the Santa Ana Field is part of the most important gas province of Venezuela: Anaco District. Its main productive zones are nal Offshore Oil Corporation (CNOOC) Chevron and ENI the field operator are partners in the development of the HZ oil and gas fields o an important technique for stimulating production in low-permeability formations and requires special consideration in designing the preced enge identified by ADMA OPCO is the time delay and subsequent lost�production between a well being completed with the drilling rig un imates of post perforation damage skin are important for designing remedial solutions and productivity enhancement operations. Underbala coiled tubing (CT) conveyance is used to optimize underbalanced perforating especially for rig-related operations. Well trajectory tempera shaped charge fired from a perforating string or perforating gun will not only perforate its targets but also possibly cause excessive damage ivity is driven by establishing a clean connection through the near wellbore zone of drilling and completion induced permeability impairment n a series of laboratory flow experiments comparing the productivity of perforations created with reactive liner charges against those created productivity is achieved by establishing a clean connection to the wellbore through the near wellbore zone of drilling and completion induce co's drilling strategy witnessed a change in the last few years by drilling horizontal and extended reach maximum reservoir contact (MRC) w s Basin in Brazil is one of the most challenging areas for completions in the world due to the lack of formation consolidation the large perce illips is developing the Magnolia field with a tension-leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico the wells reach there economical production limit and are consequently abandoned or mothballed until viable solutions are available to enh illips is developing the Magnolia field with a tension leg platform (TLP) in 4 674 ft of water at Garden Banks Block 783 in the Gulf of Mexico s situated in SPDC’s OML 22 in the eastern part of the Niger delta belt some 60kM NW of Port Harcourt. The field discovered in 1986 ators have recently launched a new industry-wide initiative on sand control reliability. The aim of the initiative is to gain a better understandi end of completion method in offshore reservoirs with sand control requirement is Horizontal Open Hole Gravel Packing (OHGP).� Thoug Hole Gravel Pack (OHGP) completions that have been installed in Greater Plutonio to date have all achieved complete annular packs and z n A-45 located in the Norwegian Sea was completed in an unconsolidated sandstone reservoir that required sand control. The lower zone major challenges in underground gas storage wells in Italy is to maximize the sand layers exposure by drilling slanted or sub-horizontal wells ravel packing is one of the most popular completion techniques due to its high reliability along with the ability to deliver high-productivity we king has routinely been used as a sand control method in open-hole horizontal wells. With the advances in drilling technology in recent year jority of the recent deepwater developments in West Africa require sand control applications. Openhole gravel packing is the preferred san gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depend gravel packing is commonly utilized to control sand production from oil and gas wells. The success of a cased-hole gravel-pack job depend n oil and gas field located off the Norwegian Coast that is due to be developed with subsea infrastructure tied back to a floating production f presents the first installation of nozzle-based passive inflow control devices (ICD) for Apache Corporation in Australasia. This recent technol sand control completions provide a cost-effective means of completing wells in the Gulf of Mexico by eliminating the need to have a rig on l for a cost-effective alternative to screens has been intensive in the sand control field. Different systems have been proposed in the past inc

ction from the Sarir field became a major concern for AGOCO at the end of the 1980s when ESPs were introduced to the field. The sanding presented as SPE�100948 at the 2006 SPE International Oil & Gas Conference and Exhibition in China held in Beijing 5-7 December 20 escribed a case study involved an investigation in a field in Libya where massive unexplained fill had been reported accompanying obstruc only acknowledged in the petroleum industry that water cut increases sand-production risk and a number of possible mechanisms have be he stacked reservoirs of the Bokor field offshore Sarawak Malaysia are prone to sand production the field-development team did not opt a duction of hydrocarbons the formation is subjected to increasing levels of effective stress resulting from the reduction in pore pressure. In presents a geomechanical study on the potential of wellbore instability and sand production for a multi-field gas development in offshore Pe c surfactant systems are used in the industry for several applications. Initially the application was focused on low-friction and solids-suspen of acid solutions injected into hydraulic fractures created in carbonate formations can be assessed at the laboratory scale in acid fracture co an acid fracture treatment is to generate a highly conductive pathway of sufficient length from the reservoir to the wellbore. Depth of penetra ng has been an integral part of Aramco’s gas development strategy for the vertical wells in the Khuff carbonates over the last several ye ng has been an integral part of Aramco’s gas development strategy for the vertical wells in the Khuff carbonates over the last several ye ecember 2003 and February 2005 eight wells were stimulated in Tengiz field in Kazakhstan using a viscoelastic diverting acid system to ev ¿½ formation (Cretaceous age Campos Basin Brazil) is predominantly an oolitic and oncolitic grainstone and packstone limestone with a b matrix acidizing in Kuwait’s horizontal openhole wells is a big challenge. Reservoir heterogeneity and the length of the horizontal wells m il and gas production from the Brown Fields is now more important than ever to the operating companies as the oil price remains record hig our water injectors in carbonate formations in Saudi Arabia sulfide scavenging prevention of sulfur and iron sulfide precipitation is a major of carbonate reservoirs is often considered a routine operation. When the reservoirs are thick (more than 200 m) the stimulation process is m acid is the most commonly used acid for carbonate acidizing due to its low cost and high dissolving power. However there are two major d iyah field is one of the biggest sub fields and older producing sections in the giant Ghawar structure. A few wells have been dead for someti s formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy.� ld in the south of Colombia was initially put on production in 1969 and has produced continuously since then. The most prolific reservoir is e of matrix treatments in carbonate reservoirs is to increase connectivity of a formation with the wellbore in the entire zone of interest. Succe y of oil exploited from Russian oilfields today comes from the Volga-Urals and Western Siberian basin where large-scale fracturing and coil nate reservoirs are heterogeneous at multiple-length scales.� These heterogeneities strongly influence the outcome of acid stimulation tre n of existing wells represents a vast underexploited resource. A successful refracturing treatment is one that creates a fracture having highe luids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water carbon dioxide (CO2)–foamed fracturing fluids were used to stimulate wells in the Waltman field in Wyoming—due to the low formation lation techniques like hydraulic fracturing which can involve large financial investments call for a basin- or reservoir-specific approach to m s and condensate drop out near the wellbore in a gas reservoir can cause rapid production decline. The liquid (water/condensate) is trappe ted wells producing from the mature carbonate formation in northern Kuwait are encroached by injected water from adjacent wells presentin (sonic and ultrasonic) of cement bond log tools are run in tandem as part of ZADCO’s standard cement evaluation program. The effect que for analyzing and modeling the pressure data from both flow and buildup periods in closed chamber tests (CCT) has been developed. servoir in the Greater Burgan field is a thin carbonate reservoir containing light oil in a 10-20 ft target zone with “good porosity.� Mat a unique methodology designed for evaluation and optimization of multi-fractured wells in stacked pay reservoirs using commingled produc l pressure transient testing using a pressure gauge positioned at a fixed depth in a well has historically been the main source of permeabi or many reasons the wellbore does not completely penetrate the entire formation yielding a unique early-time pressure behavior. Some of th s often used in pressure transient testing radius of investigation still is an ambiguous concept and there is no standard definition in the pet ngineers operating in mature fields across the world struggle to get necessary reservoir data to make their exploitation plans more realistic.ï k we present an investigation of recent deconvolution methods proposed by von Schroeter et al. (2002 2004) Levitan (2005) and Levitan e

ation of fractures is essential during exploration drilling and well completion of naturally fractured reservoirs since they have a significant im and appraisal campaigns for deepwater environments are a continuous challenge in today’s operations. Data acquisition in such enviro presents techniques for interpretation of Mini-Drill Stem Test (MiniDST) for establishing commingled Absolute Openhole Flow Potential (AOF ng using conventional separation-based technologies in low-pressure high gas rate environments typical of gas-lifted wells is a very difficult tests were performed in Yamburggasdobycha Gazprom's fields in Northern Siberia area to evaluate the performance of multiphase flowme is one of the most effective means to characterize hydrocarbon reservoirs under dynamic conditions. Such characterization of reservoirs is multiphase flowmeters (MPFM) for well test measurements is increasingly becoming a standard practice replacing conventional test separat ltesting of Gas-Condensate with multiphase flowmeters is still considered a challenge for production metering. Traditional means of well tes wet-gas flowmeters are now commercially available for the measurement of gas and liquid flow rates and offer a more compact measurem esting using portable Multiphase Flow Meters (MPFM) was implemented in ADCO Field “B with objectives to quantify the water and gas

phase flowmeters in field operations has now become a widely accepted practice especially in the range of Gas Volume Fraction (GVF) of 0 e of this study was to investigate a workflow where well test data could be used more effectively in history matching of full-field reservoir sim we present the application of the β-integral derivative function for the interpretation and analysis of production data. The β-derivative functio e derivative has become the primary interpretation tool for diagnosing well and reservoir behavior. In many situations however the derivativ sful field tests of streaming potential measurements in oil fields have been carried out: one in a horizontal oil production well and one in a ve

e atmosphere for a very long time – possibly centuries. Potable aquifers and other permeable formations (e.g. hydrocarbon deposits) mus Australia where the Cooperative Research Centre for Greenhouse Gas Technologies is conducting a large-scale demonstration project. T er long timescales. In particular the occurrence of CO2 leakage through existing wells could not only defeat the purpose of storage but also hrough the emerging process of geological CO2 storage. Also in terms of Enhanced Oil Recovery (EOR) the injection of CO2 as a pure com ndertaken in a greater variety of geological environments that has been the case previously. Often when the storage reservoirs are saline aq missions of greenhouse gases from power plants to the atmosphere and to mitigate global climate change. The CO2SINK project is a R&D p a major contributor to the current rise in the Earth's surface temperature. Reducing CO2 atmospheric concentrations by capturing emiss geological storage of carbon dioxide. During CO2 injection increasing fluid pressure temperature variations and chemical reactions betwe The Society of Petroleum Engineers (SPE) Applied Technology Workshop (ATW) on OnePetro CO2 ustry standards body Energistics (then POSC) in 2005. In November 2006 PRODML OnePetro V h Sea and set on production in October 2005. The well was drilled to 9082 m/29796 ft measured depth and has an Along Hole Depth (AH t challenges which hampered development during the 80’s and 90’s when operated by the previous owner. These include formatio the successful outcome of engineering efforts to increase extended reach capabilitie OnePetro containing hundreds of pinnacle reefs. These reefs discovered primarily during the 1970s have produced nearly half a billion barrels of pri se has increased recently. Under a high crude oil price scenario field applications of enhanced oil recovery (EOR) processes are becoming d stacked sand bodies. These thick sections have been primarily exploited and produced. Still existing are many previously considered une up when bottomhole pressure drops below the dew point.�Such an accumulation of condensate liquid in the near-wellbore region forms Gravity Drainage (SAGD) project using a representative sector model from a field with fluid and reservoir characteristics from an eastern Ve escribes the good practices and lessons learnt from a number of jobs. In addition to the technical analysis the paper also addresses the ec urrently only 50% of total strings are flowing. OnePetro impaired by excessive water production. Excess water not only reduced the artificial lift efficiency but also imposed various damages to the roduction. Problems related to non-desired water production are drastically affecting the oil production and have been an ongoing concern. ne and single-string multi-zone completions. These designs have been adopted to reduce the number of infill wells required for field develop oyed for the first time in a dead horizontal well in one of the onshore fields in Saudi Arabia. It was successfully applied by setting an inflatabl rol is becoming increasingly essential to enhancing oil recovery. Water control operations are especially challenging in under-pressured rese will seriously impact the economics of a project through lost hydrocarbon production reserves recovery and ever increasing treatment costs vels oil production profitability decreases dramatically and even goes to negative. One feasible option in this case is a rigless water shut-off n deepwater and more challenging areas around the world have become a key target for the majority of oil and gas Exploration and Product gning methods has led researchers toward its continuous investigation. The objective of this study was to characterize oil/water flow through derstanding of oil/water pipe flow behaviors is crucial to many applications including design and operation of flow lines and wells separation s allow the access to marginal reservoirs for which dedicated production might not be economic and also accelerate the recovery.�Sen urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them so lex reservoir characteristics and various fluid phases flowing from the reservoir rock to the surface could promote production interruption du ade on the feasibility of prospect development. Such sets of information include the reservoir fluid characterization and flow assurance data sequent prospect development of the hydrocarbons. Corrosion is a major concern effecting capital and operational expenditures since the p Standard correlation methods using logs cores and seismic data are sometimes inadequate whereas an extended production test may be even primary depletion. Even though asphaltene OnePetro of condensate reserves. Often these studies must begin before laboratory data become available or possibly when laboratory data are not nd volatile oil reservoirs. It was shown before that MBO could adequately replace compositional simulation in many applications. In this work A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are kn the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer m and changes in fluid properties as a result of production and injection processes. High-quality fluid data are critical for reliable modeling re aining this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid id samples using wireline formation testers (WFTs). A sound understanding of the physics of OBM filtrate clean-up and identification of firstoved reservoir management. DFA is a unique process in fluid characterization for improving fluid sampling reservoir compartmentalization e

n. In addition it can provide information for reserve assessment and producibility estimation. ��� In this paper we present compre esigned for sour hydrogen sulphide (H2S) service. This problem is compounded if production is routed to an NGL or GTL facility because ev

ed by gravitational forces thermal gradients OnePetro hole sampling of a gas/condensate fluid—unlike its oil counterpart—does not guarantee the retrieval of a single-phase fluid. The same is critically important to reservoir management particularly in deepwater projects where uncertainties are large and mistakes are costly. Com as condensate reservoir is well known for its complex behaviour due to the nature of a near critical fluid. The reservoir pressure and temper sed by a conventional pressure-gradient-analysis method was observed in situ in real time by a new fluid-composition analyzer using visible mpartmentalization in formation tester pressure surveys. However in the Niger Delta region and other offshore deepwater environments man of gravity capillary and chemical forces. Frequently non equilibrium or non stationary state conditions are also encountered for instance du planning decisions. For example in subsea wells flow assurance is a major concern and formation fluid samples from openhole logging he arrat field using a compositional simulation modOnePetro servoir fluid properties such as compositions of four or five components/groups OnePetro servoirs. There are numerous publications (Creek 1985 Lars H�ier 2000 Montel 2002 Firoozabadi 1999 Ghorayeb 2003 Fujisawa measurements for downhole fluid analysis (DFA). DFA involves an in-situ measurement of optical absorption spectra used to compute prope ning this information at all stages of the exploration and development cycle is essential for field planning and operation. Traditionally fluid in ging operations. Accurate identification of the produced fluid usually depends on the OnePetro ana subsequent isenthalpic/isothermal flash calculations that are practical for multiphase fluids in a non-isothermal environment.� These me through the production path stable emulsions may be formed. This scenario may particularly be present during the production of heavy oils tivities are moving into the ever-challenging environment around the world. ProperOnePetro analysis device with a oscillating mechanical sensor providing downhole densi OnePetro OnePetro sity and viscosity at reservoir conditions using a wireline formation tester (WFT). OnePetro s used for evaluation important details can often be overlooked such as indivi OnePetro OnePetro ervoir fluids in open hole with levels of filtrate contamination that are in many cases below measurable limits. Also the time required on sta alternatives to well testing. These tools are widely used to identify reservoir fluids and obtain representative samples for laboratory analyses h exploration appraisal and development activities moving into marginal fields and more challenging environments accurate fluid characte il gas and water without prior phase separation and provides in many cases much more accurate picture of the transient evolution of flow a uced by strong acids. One way to address these problems is to use simple organic acids and chelating agents. Unlike HCl the reaction of o ng of more than 40 oil-and-gas-bearing layers. The Ap-13 is one of the biggest reservoirs and encompasses a myriad of challenges: it is a emove damage. However most cores that are used come from sandstone quarries and the cores are largely clean and undamaged (and no hibition. Several new chemistries (two inorganic compounds and one organic nitrogen-based product) have been identified which provide im a the Gulf of Mexico and the Campos Basin in Brazil. OnePetro s of laboratory-scale experimental and theoretical studies. Experiments were carried out in three directions to understand and quantify the n he rock surrounding the perforation tunnel. This damage can lead to reduced productivity and to an enhanced risk of sand production both o of the completion is promoted by optimizing perforation characteristics such as geometry phasing and density but unfortunately it is restric carbonate scale rapidly precipitates from the produced water and causes reduction in reservoir permeability restricts fluid flow in tubing an n. Since 2003 conventional hydraulic fracturing treatments with scale inhibitor pumped simultaneously as an additive have been offered to t mising reserves. One of the key enabling technologies in this area is intelligent well completions.�Downhole inflow control devices allow leted in the Upper ZAKUM (UZ) oil field. Calcite or Calcium Carbonate (CaCO3) scale mostly found in the upper part of the production strin that may be rich in calcium strontium and barium ions this paper presents evidence for in situ sulphate stripping in a sandstone reservoir idual well history matching. This paper presents a novel methodology for delineating multiple reservoir regions for the purpose of efficient hi d well allocation factors now it can be used as an effective tool to validate fracture lineament through visualization of streamline-based flow uper giant Sabriyah oil field. For the Middle East region streamline simulation has particular significance due to the magnitude of reserves roduction since 1979. After the implementation of Nitrogen injection peak production has reached to more than 2 million stb/d in early 2000 ™s largest gas fields.� Activo Integral Burgos (AIB) is a typical example of large gas field where production declined due to gas-loading ba the past 30 years. Due to uneven sweep and pressure distribution this technique has given way to pattern floods in several gulf fields. As ions teams across the North Kuwait asset to significantly improve the operating procedure for waterflooding the Sabiriyah Mauddud field. T ezuela used to be rod pumping and top-drive progressive cavity pumps (PCPs) particularly for wells with production rates ranging from 200 . Due to the production decline of conventional light crude projects must focus on increasing the recovery of heavy and extra-heavy oils us om thin pay zones due to excessive heat loss to the overburden.� For such wells minimizing heat losses can be achieved by using micro shbone and multilateral wells. This cold development can only recover between 6% and 9 % of the considerable original oil in place existing wells and as time progressed this matured into drilling of horizontal and high angle wells. Typically drilling challenges in this area include d ed Neutral Zone (PNZ) Saudi Arabia and Kuwait. Characterization of this heavy oil reservoir is challenging due to observed variations in oil fective oil mobility profile in-situ downhole fluids analysis (DFA) as well as taken PVT samples and maintaining them in single phase condit

neous sandstone that is thinly bedded unconsolidated bearing typical heavy oil. Bentiu reservoir is composed of massive sandstone unco

oil at water cuts up to 98%. Stimulation is required to enhance oil production and extend the life of the field. An inherent problem with these

the imminent decline of lighter crude oil fields such as Cantarell (the primary Me OnePetro n a case study in Venezuela. The focus will be on practical information knowledge sharing to overcome all classical problems due to fluid b operating temperatures (150-200 C) steam presence in the gas phase foaming emulsio OnePetro atment fluids and the formation minerals. Such reactions are more likely to occur at elevated temperatures and can result in potentially dam but high-reserves potential reservoirs requires use of advanced formation evaluation techniques. The Achimovskaya formation of Urengoisk drill into ever-deeper geological horizons. High pressures and temperatures in theOnePetro reasing numbers of deep water and subsea production systems and High-Temperature-High-Pressure (HTHP) reservoir fluids have elevate lic fracturing treatment.� In certain case OnePetro lic fracturing treatment.� In certain cases excessive crosslinking while the fluid is in the tubulars can result in friction pressures that are t dequate fracture length is challenging due to the fast acid spending rates and high leakoff resulting from these treatments. The problem is e

monitoring solution with state-of-the-art intellitite welded system that allows bottom hole pressure and temperature in real time in JFYN-01 g ite Tiger) field offshore Vietnam. High temperatures (>275oF) and closure stress (>8 000 psi) combined with the fact that fracturing has to b ried mineralogical composition from interval to interval. Near-wellbore fines damage and carbonate scale damage have been reported in th ations. These fluids dissolve sizeable amounts of calcite and clays and maintain high levels of dissolved metal in solution over time with min in order to achieve oil production at commercial levels. As fields are arriving to a mature stage they require continuous improvements with he chemical system alters the formation wettability to intermediate gas wet conditions thereby decreasing the capillary forces and enhancin mperature and pressure. The technique involves adding pH sensitive dyes to pressurized single phase water samples collected using a for nd can adversely affect the producibility of OnePetro onal openhole or cemented and perforated lateral completions.� The application focuses on openhole (OH) completions in the Cleveland

nd recovery potential from this type of reservoir has risen. In this environment a multidomain integrated process enables the data and activ cture mapping combined with an in-depth knowledge of reservoir geology and geomechanics can give a better understanding to the effectiv e with the maximal horizontal stress azimuth. The knowledge of the hydraulic fracture orientation is of critical importance in field developmen bo Fm. Taylor Sand Fm. and Wilcox Fm. etc.) and shale gas-bearing formations (e.g Barnett Fayetteville Marcellus Woodford etc.). The ley Sands.� Historically these treatments have been performed using a wide variety of techniques using a range of fluids including slick w

permeability high Young’s Modulus presence of natural fractures minimal stress OnePetro OnePetro re low-permeability reservoirs that it is becoming the standard completion practice in many areas. The reasons for the success of this techn rge-scale gas reservoir that has in excess of 100 billion m3 of natural gas reserves. The main sandstone reservoir in the Guang’an field rabia and has been a prolific oil producer in the area. Several billion barrels of oil from this reservoir has been produced within the PNZ. As e northwestern part of the Greater Green River Basin Wyoming. It produces gas from the micro-darcy fluvial channel sandstones of the Up on performance for a Uinta basin development program. This technique has proven to be vital in the economic success of wells in the Uinta ng. The numerical flow models were built by integrating seismic petrophysical geological and engineering data including hydraulic fracture tandard petrophysical analysis and simple porosity cut-off technique. The problem becomes more acute in marginal tight gas reservoirs. Th OnePetro OnePetro ical in order to reduce geological uncertainty and determine well trajectory in future horizontal drilling. Challenges are often found in both ac ol plugging extended pumping time and multiple trips out of the hole. At the same time there are increasing demands of various types of f esence of fractures (natural or hydraulic) these tight reservoirs with matrix permeabilities usually less than 0.1md and porosities between 3 ssure depletion and sand body continuity are fundamental to determining the economic viability of these projects. An elusive challenge has ssure depletion and sand body continuity are fundamental to determining the OnePetro OnePetro servoirs. Pretest pressures gradients and mobilities are generally regarded as essential inputs to the reservoir evaluation model. However riobskoye field contains 30�API crude in laminated sandstones of 0.1 to 20 md at a depth of approximately 2 500 m. The complex geolo ventional formations such as coal chalk and shale. Conversely few tight-gas-sandstone reservoirs that require stimulation have realized s is known as a really challenging exploration object. The main reservoirs are located in Riphean carbonates made up of single p.u. porosity elop new techniques and strategies for evaluation and appraisal of increasingly comp OnePetro anies during next decades. Due to numerous fo OnePetro

nderestimation of reserves sometimes occurs because the formation oil can be more mobile than expected. The measurement of mobility o prematurely kill wells leading to a considerable loss in recoverable reserves. In soOnePetro pment strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate stra nd North Lukut field which is a small oil field operated by PETRONAS Carigali OnePetro ves based on a variety of diverse criteria. As part of the decision-making process companies often convert non-monetary criteria to common ctive judgment of experts. Expert judgment often considered to be less and accurate than objective data analysis. Nevertheless it is still one ld be to enable the client to make quick accurate decisions on the formations being drilled thus reducing and minimizing the geological unc d saturations and from the perspective of predicting dynamic reservoir behavior. Traditionally this input has been obtained from special core servoir heterogeneity. A common limitation of these techniques is that they do not provide two-dimensional spatial information of reservoir c s and petrophysical measurements (f/k and MICP) as long as the carbonate pore system remains simple. Once dual porosity is present it i el the reservoir heterogeneities. Interpretation of borehole images has been the key to better understanding of the sedimentary environment ia. This clastic succession corresponds to fluvial estuarine and shallow marine deposits characterized by common lateral and vertical facie properties and determining zonal connectivity across the reservoir. Information from profiling the reservoir fluids enables sealing barriers to n the developed fields of Eastern Kalimantan. This paper explains how using a formation tester equipped with two downhole fluid analyzer m ever it is difficult to correctly predict the fluid flow in the absence of proper characterization of the different flow units encountered in these re am-Shelf basin in the north eastern part of India. The analysis of this mature field carries a lot of interest not only because the sands within vity gamma-gamma density and thermal-neutron porosity with measurements unique to the LWD arena including neutron capture spectro n valuable information about their reservoirs. Until recently much of the information obtained using these sources could not be obtained w reline) GR (natural gamma ray) responses in various wells. It has been suggestedOnePetro that luating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the field n evaluating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the ssure and relative permeability. Recent advances in log analysis combined with new logging sensors that are sensitive to carbonate rock tex member. The sandstone is predominantly poorly consolidated and quartz rich. Much of the sand is medium grained although coarser sand is rom logs in a complex heterogeneous Middle Eastern carbonate reservoir.� The 795 ft conventionally cored interval consists of interbed of thin silt and clay beds.� These reservoir sands vary in thickness from millimeter to meters in thickness.� The reservoirs are highly p ell completion cost optimization. This requires the accurate identification of hydr OnePetro

osity. Afterwards saturation and volume are simple Archie applications. Resistivity anisotropy techniques can provide estimates of sand res erstanding of log responses to fluid flow and distribution than that FE of oil producers drilled in dry oil intervals. In reservoirs swept with wate esence of fractures. Natural or hydraulically induced fractures control hydrocarbon productivity due to the low porosity low matrix permeab luation of fluid type from in-situ densities identification of fluid contacts and inter-reservoir connectivity. Fluid sampling and downhole forma eir origin nature orientation and impact on productivity of Lower Cretaceous hydrocarbon reservoirs. Studies identified a conundrum with r s reservoirs in the Al-Khafji area. 3D seismic data are acquired aiming at to delineate the stratigraphic and possible strati-structural traps an behaviour. Conceptual models were used to constrain the number of realizations OnePetro all of es. The spatial characteristics of geostatistical methods in variogram kriging and stochastic simulation have made them the tools of choice bit heterolithic interbedding with vertical heterogeneity and a wide range of layer flow properties. This paper describes methods of real-time minations. NMR helps to 1) detect thin beds 2) determine fluid type and if hydrocarbon is present 3) establish the hydrocarbon type and vo offshore high pressure-high temperature high-an OnePetro n by using a new methodology for depth and survey measurements corrections. LWD depth measurements are often considered inaccurat d in 1938 and it went on stream in 1946. Most ofOnePetro th supported by field studies and micro-seismic observations. This paper presents a study of stress reorientation around horizontal wells. Stres ost all operations in oil or gas production.� A continuous profile of these parameters along the depth is essential to analyze these problem verlying shaly formation. Drilling through such depleted reservoirs can cause severe fluid loss and drilling-induced wellbore instability. Accura e for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements. e for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements. e for establishing the stabilized deliverability performance of multi-layer commingled systems using multi-rate production log measurements. e reservoirs that have moderate-to-low porosity were deposited in an inner- to midramp warm marine environment. The fracture systems pla ssociated with faults. Thus fracture characterization of this complicated area is very important to understand the reservoir behavior and he field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomi h) have been producing for more than thirty years. All the available informations indicate that the producing layers subdivided into Upper an was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limeston

ng time-lapse resistivity pressure and flow rate data from a permanent downhole Electrode Resistivity Array (ERA) and pressure and a pr nge to the industry. The practice of performing a drill stem test (DST) over a significant reservoir interval and attributing the properties of the w in East Kalimantan-Indonesia over decades despite technological advances.� One possible reason has been postulated as alteration o hods are well documented. Comprehensive characterization of the wellbore rock relies OnePetro o (NMR) in Naturally Fractured Clastics Reservoirs of very low porosity (≈ 3.5%) in the Devonian of the Bolivian Sub-Andean reveals info sentative samples of the different fluids encountered in the formation are obtained. Usually the wireline or LWD petrophysical logs will guide s. These formations usually exhibit low resistivity contrast between water and hydrocarbon zones and high apparent clay content. Calculate epend on the acquisition sequence inversion parameters and the logging environment. Some modern NMR logging sequences are intende technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recogniz ntervals in the Gulf of San Jorge Basin oilfields. These methodologies have been successful only in a limited number of cases and a solutio complex completions. Evaluating the performance of these horizontal producers is critically important for improved reservoir management. C esented. This methodology uses NMR log data and electrical image data when avail OnePetro is lower than the pore pressure of the target formation of interest. The most widely recognized benefit of UBD is the reduction of formation d Mishrif formation. Developed as a limestone sedimented in a mid-ramp environment it generally consists of fine-grained packstones to wac opment. Traditional methods of identifying reservoir compartmentalization such OnePetro OnePetro oir compartmentalization for instance can result in non-optimal well placement completion strategy and facilities design as well as large e nalysis (DFA) is a new tool to reduce uncertainty associated with reservoir connectivity. Fluid data from DFA logs and various laboratory ana y for establishing the stabilized deliverability performance of multi-layer commingled reservoir systems using multi-rate production log measu ery oil fields where remaining oil saturations approach residual oil saturations it is possible to test these estimations using Pulsed Neutron hannel and bar sands with limited lateral and vertical extension. Relying only on conventional openhole log data and performing correlations

ements (vertical distribution and direction) in the South Priobskoe field in western Siberia has created the need to determine the orientation e difficulties arises due to phenomenon known as supercharging which is caused by mud filtrate invasion. The supercharging results in an i sensitive to reservoir and operational constraints and uncertainties. This so called “Optioneering process was an iterative multidisciplina ertainty associated with the data acquired in the exploration and appraisal phases which can be ultimately used to forecast reservoir behav mps (ESPs).� ESPs are an attractive alternative since they can achieve lower bottom hole flowing pressures.� This can accelerate prod lmost as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide production and efficiency. Using appropriate processes tools and technology production surveillance is able to be conducted in efficient ma gressively pursuing production increment ventures one of the main components being the development of stringers which are present amon es integrated reservoir engineering formation evaluation geological and geophysical contributions.� The objective of this paper is to exem n in the Waddell Ranch Project. The Project was implemented in three phases over a period of three years beginning in June 2000.�A and can increase reserves in stacked reservoirs. The approach will potentially reduce associated costs risks and uncertainties in spite of c otential is often not realized. Unlike greenfield developments mature oil fields deal with existing infrastructure and fluid export schemes with of Moporo Field located in western Venezuela different exploitation schemes were evaluated where intelligent completions have been high ld development plans surface facility design/de-bottlenecking uncertainty/sensitivity analysis and instantaneous/lifetime revenue optimizat into the tubing.� The injected gas reduces the bottomhole pressure thereby allowing more oil to flow into the well.� The optimal amou reservoir management and production strategy which optimises future recovery from an oil rim reservoir in the Betty Field offshore Malaysi tidisciplinary optimization team was built. The standard practices for production enhancement opportunities include logging nodal analysis e the heat goes at various times and places during OnePetro th ield development. Handling uncertainty and risk using probabilistic approach i OnePetro presents the full workflow for optimzing production and injection cycle times with the help of a simplified reservoir model (SRM) through the egies can be developed within a new systematic workflow using existing applications from many E&P departments. Detailed production da urface facility levels using only their respective knowledge experience and engineering tools without limited coordination between them so d time for project execution has been significantly reduced.� Using these concepts it is now possible to conduct integrated studies succe in the development of the XJG oil fields in the South China Sea. The XJG fields are in a mature production phase and challenge COPC (th of the fields in the Oriente basin of Ecuador and neighboring Mara��n and Putuma OnePetro ustain target rate until mid of 2004. Artificial Lift is part of the long term production sustainability solutions for Khafji Field necessitated by the produced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is incre harged to demonstrate within a one-year time period measurable improvement in well productivity in the Saih Rawl field of Oman. Althou al low permeability reservoirs. The workflow was originally developed for gas reserves evaluation of the Lower Vicksburg (LV) sands and the r a client to agree to a forward contract for a service to be performed at a future date at some specified price. In this case the service provid

aximize hydrocarbon production in deep water turbidite reservoirs. The deep reading directional electromagnetic tool a latest-generation LW orizontal section has been drilled in three horizontal production wells all within Palaeocene-aged Balmoral turbidite sandstones below a Sel egions that are most favorable for well placement.�A technique is developed to apply this method to the problem of field development wh operations begin. Real-time downhole pressure data and surface flow rate information can provide a significant set of calibration informat ater flooded fields.� It targets bypassed reserves to improve production and ultimate recovery from such fields at once.� The method ly gas breakthrough and gas cycling can cause serious problems especially in a co-mingled production environment and heterogeneous ge project’s net present value (NPV) as modeled in a reservoir simulator. This paper has two main contributions: first to determine the effe f heavy oil and natural bitumen recovery. An optimal production rate and corresponding bottomhole temperature and pressure should be ma ace.�The solutions are derived assuming a cuboid shaped reservoir using a method of integral transforms.�The method can be appl e. Assuming a vertically stacked system of layers an analytic solution within each layer can be derived using a method of integral transform ayesian formulation and its implementation have difficulties in three major areas particularly for large scale field applications. First the CPU ral limitations. First the CPU time depends on the data points which are large for any brown fields of long history; second it requires large m process. A new criterion for measuring the deviation of the simulation mode OnePetro OnePetro orks have been developed to assist in the history match of reservoir models. This pape OnePetro pal Component Analysis which is currently used in computer vision applications. During history matching the spatial reservoir parameters at

sociated with heavy oil thermal recovery. The primary focus of the simulator is on the physics associated with steam injection and Steam Ass phases and components any component existing in any phase and requires no special ordering of phases or components. This type of fo ed difficulties modeling long horizontal wells due to the combined complexity of the wells and the reservoir. This reservoir is located in an off

ction wells. They are used to maximize the well to reservoir contact and improve oil recovery in a cost efficient manner. This is especially tru ector model and or small scale multi-well level is generally well understood.� InOnePetro widespread influence on implications for wel OnePetro ing phases must be solved. When this equation system is solved implicitly a sy OnePetro e performance of oil and gas wells. This is achieved by curve fitting the past production performance using the rate-time data and extrapolat the productivity of producing wells especially in tight gas formations. The fracture-cleanup process is complex and may suffer from the pre able option. However despite the state of the art techniques such as multiple fracturing of horizontal wellbores the gas recovery from thes n carbonate plays where acid and fracture stimulation can be used to improve productivity the technique can be used for tight reservoirs an nd improve the development of gas-condensate field. In recent years numerous research efforts were focused on the developing efficient n anes or natural fractures. In shallow or over-pressured formations interfacial slip between formation bedding planes is possible when the ef nd post-fracture production profile leading to an optimum design and maximum production enhancement. The paper demonstrates the adv d when analyzing well test data.1 Current practices to quantify the non-Darcy flow effect in a vertically fractured well are mostly based on th contributes to the commingled well production. This paper presents a stochastic analytic production analysis technique for multistage hydra erpretive models of the boundary-dominated flow performance of vertically fractured wells located in closed rectangularly bounded reservoir r of hydraulic fracturing treatments in highly deviated wells. The non colinearity of the wellbore axis and of the fracture plane has initially ind erical model was developed which takes into account the interaction of steel casing cement and surrounding rock and allows for a curved any methods for building ANNs have appeared in the last 2 decades. One of the continuing important limitations of using ANNs however is ed. It is now a common practice to generate OnePetro by severe variations in facies. These challenges in the static modeling have a strong impact in the dynamic modeling which can be summa well during the process of water injection. The model is obtained from a theoretical treatment accounting for both mass transfer and heat tr mobility ratios when displaced by water in fields under waterflood or with active aquifers.This causes a triple hit on the recovery factor: Poo s of several stacked sands and is highly faulted resulting in a complex system of several compartmentalized reservoirs. The drive mechani ainty. Although some research is available in literature usually the effects of data uncertainty on material balance calculations are rarely con fe. While elaborating field development additions an operating company meets a number of problems falling into two categories: The prob orous media. Thermal diffusion pressure diffusion and molecular diffusion are included in the diffusion expression from thermodynamics o their impact on investment decisions have become very crucial in management decisions. This has seen the stocks of both experimental d ir simulation. In our full field review a systematic procedure was developed to OnePetro ation of –div(K(x)grad u) = f(x) the equationdescribing fluid flow through anisotropic porous media. The permeability tensor K(x) is allowe d with the use of dual-porosity/dual permeability models and the direct numerical simulation based on the “Sugar Cube19 representation be connected to the fracture system or be isolated in matrix material which constitutes a triple porosity system.� The modeling of the disp stribution than conventional statistical and geostatistical techniques allowing the integration of geomechanical data and models into reserv

actured Jurassic carbonate formation. These reservoirs contain multiple fluid t OnePetro OnePetro because of the capability to calculate fluid flow in multi-million cell geological models with reasonable CPU times. Recently streamline simu twork of fracture channels. This representation is conventionally described by a dual porosity model which is the one used in the present w gical models of petroleum reservoirs. These models are characterized by complex shapes and structures with discontinuous material prope sms; understand behavior of a particular proces OnePetro of various methods and research groups to quantify the uncertainty in the prediction of cumulative oil production. Previous results reported uracy. Especially in risk analysis where complex relationships between the uncertaint OnePetro ce facilities - because of thermodynamic changes that affect the flowing brines. These changes may be induced by temperature or pressure pment mandate significantly improved and timelOnePetro it is applied to heavy oil reservoirs.�� Th OnePetro d is that the pressure field can be updated relatively less frequently and the saturations can be transported along the streamlines defined b essible fluids in porous media with mass exchange between phases. In this work we consider a streamline method for two phase compres gas field. Usually performance evaluations for infill wells are conducted using either much generalized statistical methods or numerical simu data and the assessment of uncertainty in forecasts for complex large-scale problems. A handful of papers have discussed reservoir chara eostatistical reservoir models and uncertainty assessment. Real time monitoring of pressures through permanent down-hole gauges is a re etween the ICDs is open or partially obstructed by the presence of packers and we describe the application of this model in a full-field simu omputationally than compositional simulation. But a principal limitation of black OnePetro aturally fractured Jurassic carbonate formation. These reservoirs contain multiple fluid types (gas-condensate and volatile oil) at near-critical andstone formations is known to be strongly water-wet. In contrast most carbonate reservoir rocks are believed to be mixed-wet or oil-wet nd its contribution in formation damage. In the study an advanced laboratory test prog OnePetro OnePetro f the discussion concerns the inertia resistance factor or the so-called beta factor β in the Forchheimer equation and whether the beta facto to open-hole formation evaluation often fail to predict how much oil should flow from them or even the location of the free water levels. A ts time and to this day still remains the largest onshore gas field in Dubai. This reservoir is characterized by a relatively low-porosity over-p the stress distribution around the wellbore induces deformation depending on many factors ranging from wellbore pressure history and roc Smarter.�Participants in the Forum have granted permission to present this paper on the basis that the authors are neither representing ormer Soviet Union a lot of attention was paid to oil recovery problems. Unfortunattelly the unfavorable economic climate of the late 1980-s 1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with bot cement sheath. The customary procedure is to use a model to predict potential failure scenarios and to subsequently design a sealant mat owever field studies indicate that large volumes of hydrocarbons remain located OnePetro ng. Since the formation sigma response is proportional to the salinity of the format OnePetro OnePetro ng oil recovery and reducing water cut. This paper presents a case study from the Bahariya Formation a heterogeneous fluvio-marine chan oth monobore and multilateral horizontal wells. However a clear understanding of zonal or lateral branch flow contributions still remains an i ce limitations in the short string section of the dual completion wells. The logging program was initiated in Kuwait Sabriyah Field where ther terpret pressure buildup data in Chayvo Field. With a lateral reach in excess of 8 km acquiring production logging data is difficult.� Mem esult from the absence of early detection of a condensate bank in the near well bore OnePetro ironments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is cont ironments for fluid sampling with formation testers. Low permeability indicates that the drawdown while sampling will be high but this is cont oring of bottom-hole pressure and temperature of two stacked reservoirs using one vertical observation well in a Saudi Aramco field. Perma voir conditions and results are presented for two wells in the Norwegian Sea. The measurement technique for use with wireline formationare evolving. A deepwater field in the Gulf Of Mexico (GOM) consisting of numerous wells with permanent bottomhole gauges has been on as and induced microseismic activity was monitored from a nearby observation well. The objective of this microseismic monitoring campaign metrically fracturing must adhere to mass balance equations. Therefore proppant placed in the fracture must be accounted for in the creat voir characterization purposes as well as the key element for identifying remedi OnePetro understand the flow distribution of bitumen and water along the horizontal reservoir interval. If this distribution is understood the distribution measurements to evaluate the formation inflow into a wellbore in which one or more of the completed intervals may be located in the annulu easurements for the evaluation of the formation inflow into a wellbore of which one or more of the completed intervals may be located in th of the backscattered light. This paper details a novel application of this technology using an optic fiber embedded in a 1/8th inch slickline ca open hole gravel pack lower completion in Enfield field Australia. The principle of the technology involves positioning a number of different ance. Traditional methods of estimating these parameters particularly for real-time detection and diagnosis of production anomalies have b ince they have a significant impact on flow contribution. There are different OnePetro OnePetro

on of the economic potential of the reservoir. Without this understanding a company's field development and operational decisions may not moving fluids. Low flow rates in horizontal wells means the fluid holdups in the stratified flow are very sensitive to the wellbore inclination an w below saturation pressure in some structurally-high areas where gas cap has increased in size compared to very small initial gas caps in t rstanding of reservoir characteristics and fluid movement causing production hindrance in an offshore horizontal well. The field example com aiming at the optimum oil production. Optimization of an oil producer is not easy as it might seem to be. Moreover oil price increase prom lping to quantify changes in rock and fluid properties along the wellbore to define hydraulic flow units and to understand the reservoir archi y to optimal reservoir drainage. However hitherto it has not been possible to monitor reservoir pressure changes in individual layers after a the warm-up phase of a steam-assisted-gravity-drainage (SAGD) well pair. A sequence of microseismic events was recorded with signal ch red Pereriv B C and D reservoirs. Restricted wellhead access high rates and differential depletion of the different reservoir intervals limit c g reservoir connectivity drainage and flow assurance. For those wells requiring sand control an additional constraint is that sandface sens l permeability conduits— “thief zones— if any. In the Sabriyah field in Kuwait dynamic measurements showed evidence of thief zones

ental to the workflows that target the optimization of the economic potential of the reservoir. Without an accurate understanding of productio re. Optimum and accurate determination of multiple phase fluid entry requires two primary measurements: 1) holdup or the cross-sectional UBD) horizontal wells. This approach will work in mixed-wet reservoirs and is particu OnePetro OnePetro itoring. Behind casing resistivity an important member of the comprehensive analysis behind casing services suite provides the required a fshore Abu Dhabi. The injected water preferentially follows the path of the of higher permeability zones since injection is done into formatio t. We will also show the benefit of the optimized casing material on the resolution of the crosswell EM resistivity images and describe the m and Water Alternating Gas) in a giant field in the Middle East. Cross-well EM data will help optimize sweep efficiency identify bypassed pa on from CBM is dominated by US production of 1.6 Bcf/year where an estimated 20 000 wells are in production from CBM reservoirs. Wyo called as cleats define the reservoir character and fluid flow potential. Cleats are commonly mutually orthogonal and occur perpendicular or ores for more than twenty years. However direct fracturing of coal seams has been notoriously inefficient. High fracture pressures in coal se an effort to improve well economics and to reduce the number of surface locations in populated areas the number of wells being drilled an mmercial success in producing these reservoirs depends to a large extent on successful hydraulic fracturing.� There is growing evidence BM) formations such as the Horseshoe Canyon in the Western Canadian Sedimentary basin. A typical well has an average of 20 pay zone d States.� With effective stimulation techniques these wells have demonstrated favorable economics compared to vertical wells in the sa rization efforts have been made and completion practices established to help understand the Barnett Shale reservoirs. The borehole image While shallow heavy oil reserves are extracted from pit mines deeper reserves can only be extracted through wells. Production of these res technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized al U.S. dry gas production. Typically Barnett Shale wells exhibit a rapid production decline following the initial hydraulic fracture stimulation arbonates at high reaction rate to create flow channels (wormholes"). The high reaction rate often needs to be reduced to allow wormholes elivering the required rates from Saudi Aramco fields. Therefore this form of artificial lift was selected to increase production rate from one nada's nonconventional oil reserves are estimated at just over 1 trillion barrels an OnePetro g and the wells are unable to flow naturally. Over the years a number of artificial lift techniques have evolved as a result of extensive researc had been drilled practically all the reserves of the main reservoirs within the production targets were put into production. There emerged a dstone gas reservoirs in this field have net pays with a thickness greater than 300 m and an average true vertical depth (TVD) of 1 400 m. a. This new method places sliding sleeve valves in the casing string and completes the well with normal cementing operations. The sliding s orizon. The Cartojani structure is located in the central alignment of the Moesic Platform. It is a monocline with large dimensions and low lay lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.� Particularly important in this work has been the lls to optimize gas recovery in wells that produce free liquids in conjunction with the gas.� Particularly important in this work has been the one with “good porosity.� Matrix permeability is low and natural fracture density can be quite variable in this reservoir.� Thus this re has relatively heavy oil in place that is high in viscosity. With the understanding OnePetro ervoir Contact (MRC) Multilateral (ML) and Smart Completion (SC) deployment in Ghawar Field.� The well was drilled and completed as uids across the reservoir strata. Historically completions with cemented casing packers conformance controlling fluids/gels and selective um reservoir contact (MRC) multilateral (ML) and smart completion (SC) deployment in Ghawar Field Saudia Arabia. A well was drilled an ars as part of the reservoir development strate OnePetro ontal and multilateral wells in all types and shapes. Horizontal and Multilateral applications become more commonplace to improve the well em was designed for perforating wells lifted with electrical submersible pumps (ESPs). The purpose of this project was to develop and apply e pump (ESP) system performance data. The approach extracts unbiased information from performance data and permits lifetime modeling ginning of the gas development program. Various types of acid systems including conventional emulsified and surfactant-based have been along the maximum principle stress and dominant fault orientation (northwest/southeast). Open-hole completions were considered the best

n permitted and more than 200 wells are now producing. The lateral play began in Richland County Montana and the success there is now s in the Western Siberia basin as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydra rtical wells in the Khuff carbonates over the last several years. During acid fracturing the wormholes created by the reaction with the format e largest oilfield in Western Siberia. Placement advantage of fiber-assisted fluid already becomes obvious after initial campaign of four fract d water blocks. As the gas reservoirs being stimulated become tighter the perceived value of these additives has grown. This value must be acture height containment in layered formations. It has been well documented that in situ stress contrast is the dominant parameter controlli letion and declining quality of reserves have resulted in escalating drilling completion and workover costs per unit of gas produced. This in th disposing flowback and produced water to reduce costs handling the logistics of getting enough water to hydraulically fracture the well a voir’s deliverability and what the optimum fracture half-length is as a function of geological setting and stress state.� The application a depleted sandstone formations located in Bachaquero T�a Juana and Lagunillas fields in West Venezuela. This technique combines stim from underlying water zones by a weak stress barrier. Operating and service companies alike applied various techniques to prevent the bre red over vertical and deviated wells offering the advantage of maximized reservoir contact higher production rates and better access to res cuts. These wells are commonly not considered as good candidates for matrix stimulation. Water based treating fluids would enter prefere Complex geology and low permeability are the common denominator in today’s environment. Developing reserves under these condition tain the economic operation of their valuable assets. Large quantities of reserves OnePetro OnePetro wells to achieve maximum reservoir contact to maximize well productivity. This strategy has proven very successful over the past few years ure. In this environment emphasis is placed on OnePetro hi OnePetro pproximately 30 000 bopd and is on decline. A joint team from ONGC and Schlumberger carried out a rigorous process of candidate select uction performance of a vertically fractured well located in a closed rectangularly bounded reservoir.� The solution for dimensionless prod ed formations exhibit a non planar or complex set of micro seismic events. This OnePetro d service companies have gathered significant amount of experience and knowledge. The sweeping success of hydraulic fracturing in West ique.� The evolution of the completion technique has reached the point that OnePetro OnePetro orporation. This new method placed sliding sleeve valves in the casing string and completed the well with normal cementing operations. The g sleeve valves in the casing string and complete the well with normal cementing operations. The sliding sleeves would then be opened o r existing programs used with soft rock formations often do not provide satisfactory treatment designs. Difficulties emerge because hydrau ons without the use of polymer additives.�VES fluids do not form polymer filter-cake and thus viscous resistance of the fluid flowing th prove the Olmos production in the Caterina SW field in Texas. The reservoir is chOnePetro mped using a solids-free liquid CO2 foam-based visco-elastic surfactant (VES) fluid system in Morrow Sand reservoirs located in Southeast

mance in this area was not promising. Well Raguba E-97 in this area was not producing OnePetro ssful implementation of acid fracturing treatment in Marrat field. The acid fracturing treatment is quite challenging due to presence of high p rac and Pack completions exhibit positive skin values and traditional hydraulic fracture completions show discrepancies between the placed eservoirs.� This existing technology is being utilized in new and innovative ways to provide operators a clearer picture of the fracture dev or this behavior are related to the characteristics of the porous media and are OnePetro rforming accurate borehole deviation surveys for hydraulic fracture monitoring (HFM) and neglecting the effects of the deviating borehole tra

acid; without nonuniform dissolution along the fracture face the fracture will close after pumping ceases and little lasting conductivity will b act the field development strategy. The correct estimation of the fracture dimension is critical to maximize the recovery factor of heterogeneo nsight about the fracture height (near-wellbore vertical coverage) of proppant-packed fractures. The existing tracer technology has a numbe here are two producing horizons of Jurassi OnePetro lity oil reservoirs there is still no simple practical production forecasting methodology for hydraulically propped fracturing stimulations for t sandstone reservoir using a numerical model. The fracture was explicitly modeled as a set of high-conductivity cells. At the gas velocitie rmeability formations under downhole reservoir conditions a severe pressure drop occurs at the tip of the fracture and a lag zone develops of acids such as regular in-situ gelled and emulsified acids have been used in order to achieve optimum fracture length and conductivity. hematical model used in this work is a practical alternative to estimate the degree of stimulation by means of a Stimulation Index (SD) and f ault. Fracture orientations were identified through a combination of alignment of event locations polarization of the seismic waves and injec problems for well completion. Various models have been developed to predict the onset of proppant flowback but the physics of the phenom atment is studied by taking into account the production induced stress field surrounding the initial fracture. It is shown that the propagation p nt frontal displacement of fluids from subterranean environment. Entrapment of residual fluid by the displacing one lowers down the displac xtent. An excessive fracture length may lead to an earlier than desired increase in water cut. Uncertainty in propped fracture dimension is re

a Joint Industry Project active since the year 2002. It is well documented in the literature that hydraulic fractures although successful often ctors eighteen producers and one gas injector to be completed in more than 4 300 ft of water depth. In order to maintain the oil production ast Brazil – Carm�polis and Sirizinho Fields – on the revitalization of the oil production. The purpose of this work is to demonstrate th en made to reproduce their effects on fracture growth using numerical hydraulic fracture models. Such offsets have long been recognized as on to gas lift a well. The gas lift gas is produced downhole and bled into the production tubing via an auto gas lift valve designed for gas ope ix high rate gas fields currently on production with several more in planning stages. All of the wells require sand control and this has resulte rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing op rs being eclipsed with open-hole technology. These completions have allowed multiple zones to be fractured and the benefits of utilizing op hole wells is preferred to maximize reservoir productivity. Some questions that always come up for this type of wells are: will it be necessary ies that allows commingled oil production from multi-laterals wells in Shaybah inside expandable liner.Slim intelligent completions technolog water coning towards the heel (water can breakthrough anywhere in the well not only at the heel due to permeability (K) variation and proxi ology has evolved from intervention-less completion for sub-sea wells to new applications where intelligent completions are delivering better etion technologies that allows commingled oil production from quad laterals wells in Abqaiq field. Many intelligent completions wells have be th respect to properly incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if w permeability rock (Colton sandstone) are presented. The focus of this experimental study was to assess the effects of discontinuities on h PL) measurements with nodal analysis evaluation. This allows the effects of vari OnePetro ciently to improve the appraisal process and avoid unnecessary expenditure. At the same time an accurate reservoir characterization is the ally coincide with an increase in depletion water cut or changes in the artificial lift mechanism used to produce the hydrocarbon. Sanding is and shot density while minimizing perforation damage.� However in tight carbonate reservoirs creating deep and clean perforations may pleted thus exposing the formation to potentially damaging kill fluid. To obtain a perforation tunnel with maximum productivity this transition in intervening highly deviated and long section of horizontal wells under live condition where slickline and E-line have difficulties. This pap District. Its main productive zones are the Merecure and San Juan formations which are sandstones characterized by their high permeabiliti pment of the HZ oil and gas fields operating as the CACT Operators Group (CACT) in the South China Sea. The HZ fields are stacked thin onsideration in designing the preceding perforating job. Aligning the perforations along the direction of maximum geological stress known a ing completed with the drilling rig until it is acid�stimulated using a multi purpose barge and put on production. Some wells in�ADMA O enhancement operations. Underbalanced perforating (UBP) which is widely used in well completions induces transient fluid flow that provid operations. Well trajectory temperatures and fluids can create uncertainties on both depth control and the accuracy of hydrostatic cushion so possibly cause excessive damage or swell to its carrier. Comprehensive understanding of the post-perforating conditions of the perforato on induced permeability impairment commonly referred to as the “near wellborOnePetro liner charges against those created with conventional liner charges. Three of the tests involved shots into an outcrop carbonate rock called ne of drilling and completion induced permeability impairment commonly referred to as the “near wellbore damaged zone. This connect maximum reservoir contact (MRC) wells. One of the objectives behind this strategy is to improve the well productivity by maximizing oil prod mation consolidation the large percentage of fines present in the reservoir the heavy oil the low frac gradients the low net-to-gross ratio th nks Block 783 in the Gulf of Mexico. The wells target multiple zones resulting in complex directional wells with 50–60� maximum hole viable solutions are available to enhance there production to an economically feasible level. The Hawtah field (see Figure 1) discovered in t nks Block 783 in the Gulf of Mexico. The wells produce primarily from thick fine-grained Pleistocene reservoirs. Because of the long length court. The field discovered in 1986 currently has 9 wells completed and 13 drainage points. Well A-4L is one of the completed intervals on iative is to gain a better understanding of Sand Control Completion (SCC) syste OnePetro Gravel Packing (OHGP).� Though gravel packing is a proven method to stabilize the well bore controlling sand and maximizing product eved complete annular packs and zero mechanical skin factors resulting in well productivity indices that are significantly greater than expe quired sand control. The lower zone was completed OnePetro rilling slanted or sub-horizontal wells through several shale bodies to obtain high gas rate performances during the production and the injec ability to deliver high-productivity wells. Currently there are two techniques used for gravel placement one utilizing low-viscosity carrier fluid s in drilling technology in recent years horizontal wells with lengths ranging from 2 000 to 6 000 ft have become more common. Executing th gravel packing is the preferred sand control technique adopted by many operators in this region. It is considered one of the proven metho a cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and cased-hole gravel-pack job depends on the ability to effectively pack perforation tunnels which act as conduits between the reservoir and t e tied back to a floating production facility. Nine horizontal oil producers and four S-shaped gas producers are planned and all will require so n in Australasia. This recent technology was simultaneously applied in a production well and a water injection well and served as a demons minating the need to have a rig on location. To date six screenless completions have been performed for a major operator in the Gulf of Me have been proposed in the past including various solutions based on permea OnePetro

introduced to the field. The sanding severely impaired the performance of field and consequently led to significant economic loss. AGOCO na held in Beijing 5-7 December 2006. Abstract Sand production is a major concern for many operators. It can impact production cause e een reported accompanying obstruction of production for majority of production wells since the onset of production indicating possible sand er of possible mechanisms have been proposed. This paper presents the results of a series of laboratory perforation-collapse tests aimed a field-development team did not opt a priori for gravel packs in every well. While OnePetro m the reduction in pore pressure. In weak but consolidated sandstones this can lead to shear failure in the rock surrounding the perforatio eld gas development in offshore Peninsular Malaysia. The objectives of the study were 1) to develop strategies to maintain mechanical and sed on low-friction and solids-suspension (fracturing and CT-cleanout) characteristics of the fluid. In the last 4 years the application of visco e laboratory scale in acid fracture conductivity tests that mimic the conditions in an actual acid fracture treatment. We conducted a series o oir to the wellbore. Depth of penetration of live acid is the critical factor in determining the success of an acid-fracturing treatment. Depth of carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Durin f carbonates over the last several years. The Khuff formation is a deep gas carbonate reservoir that is ideally suited for acid fracturing. Duri coelastic diverting acid system to evaluate the effectiveness of this system in achieving diversion and zonal coverage in large limestone re ne and packstone limestone with a bottomhole static temperature (BHST) of about 150�F. The formation permeability often exceeds on d the length of the horizontal wells make acid placement and diversion difficult particularly in high-water-cut (WC) wells in which water has b s as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low d iron sulfide precipitation is a major requirement during acidizing treatmen OnePetro n 200 m) the stimulation process is much more complex because factors such as reservoir heterogeneity damage to each zone matrix min wer. However there are two major drawbacks associated with using concentrated HCl solutions in deep wells. The first is its high reaction ra ew wells have been dead for sometimes due to high water cut (60 to 80%). In all cOnePetro m 20 mD to as high as one Darcy.� However the production from this formation OnePetro is oft then. The most prolific reservoir is the Caballos Formation a thick (250 ft avg.) laminated sandstone located at a depth of 6100 to 7500 ft in the entire zone of interest. Successful matrix treatments depend on the uniform distribution of the treating fluid over the entire interval. W where large-scale fracturing and coiled tubing operations have been on-going for the past six years.� In the mainly brown fields tertiary re e the outcome of acid stimulation treatments which are routinely performed to improve well productivity.� However most previous studies that creates a fracture having higher fracture conductivity and/or penetrating an area of higher pore pressure than the previous fracture. Re ons that are more sensitive to water treatments (high capillary pressure swelling clays etc). In particular the Frontier Formation located in B yoming—due to the low formation permeability and rock properties—and have been proven effective but still not perfect. Limitations on t - or reservoir-specific approach to maximize production. Integrated solutions use a performance-based process that integrates petrophysic e liquid (water/condensate) is trapped near the wellbore due to strong capillary forcOnePetro d water from adjacent wells presenting a challenge for the operating company. Greater oil demand coupled with limited surface water handli ment evaluation program. The effectiveness of these tools and their evaluations are often challenged and are not regarded as a replacemen r tests (CCT) has been developed. It can be used for estimating the key reservoir parameters such as reservoir pressure permeability and one with “good porosity.� Matrix permeability is low and natural fracture density can be variable in this reservoir.� Thus this reservo reservoirs using commingled production. The specialized diagnostic procedures are based on rate-transient analyses and uses historical pr y been the main source of permeability and skin estimation in formations. However if a well is completed as a multi-layer commingled produ y-time pressure behavior. Some of the main reasons for partial penetration in both fractured and unfractured formations are to prevent or d e is no standard definition in the petroleum literature. The pressure diffusion corresponds to an instantaneous propagation of the pressure s eir exploitation plans more realistic.� Pressure transients are the most effective way to understand the dynamic behavior of the reservoir. 2004) Levitan (2005) and Levitan et al. (2006) and Ilk et al. (2006a b). These works offer new solution methods to the long-standing deco

oirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formatio ions. Data acquisition in such environments requires reservoir information of the highest quality before expensive development plans can be olute Openhole Flow Potential (AOFP) in deep water exploration wells in India. These gas bearing reservoirs are vertically heterogeneous w of gas-lifted wells is a very difficult operation. Owing to low retention times of the gas the quality of separation and existing instrumentation e performance of multiphase flowmeters in gas-condensate reservoir applications. The remoteness of the operation and the roughness of w uch characterization of reservoirs is as accurate as the data used for interpretati OnePetro e replacing conventional test separators. These MPFMs are usually tested and calibrated in laboratory controlled flow loops using idealized etering. Traditional means of well testing have been deployed for years and used consistently for reservoir and production management. Ho nd offer a more compact measurement solution than does the traditional separator approach. The interpretation models of traditional multip ctives to quantify the water and gas production evaluate the performance of slugging/intermittent wells for procurement actions evaluate th

of Gas Volume Fraction (GVF) of 0 to 85%. There is still some doubt about the performance of this type of device especially in the High (9 ory matching of full-field reservoir simulation models and also in situations where existing simulation models could be used in well test interp duction data. The β-derivative function was recently proposed for the analysis and interpretation of pressure transient data [Hosseinpour-Zo any situations however the derivative of the measured pressure data is uninterpretable or worse misinterpreted because of various artifac al oil production well and one in a vertical water injection well. Pressure transients were created and the streaming potentials generated by

ns (e.g. hydrocarbon deposits) must also be protected against CO2 contamination. Wells are generally recognized as a weak spot in CO2 arge-scale demonstration project. This estimation is the first step of a geomechanical study on seal integrity. One principal stress is assume feat the purpose of storage but also badly affect human health or the environment. Indeed cement degradation and casing corrosion in inje ) the injection of CO2 as a pure component or as part of a mixture has proved to increase the productivity of oil and gas reservoirs. Optimiz the storage reservoirs are saline aquifers exploration data for proposed injection sites are extremely sparse. The special behaviour of CO2 ge. The CO2SINK project is a R&D project mainly supported by the European commission the German Federal Ministry of Education and R c concentrations by capturing emissions at the source—power plants or chemical units—and then storing them in subsurface reservoirs tions and chemical reactions between fluids and rocks inherently affect the state of stress inside the reservoir and in its surroundings. Besi

and has an Along Hole Depth (AHD) reach of 7593 m/24911 ft which is a world record for Extended Reach Drilling (ERD) from a floating vious owner. These include formation instability directional-drilling control issues and thin complex reservoirs which are poorly imaged on s

ced nearly half a billion barrels of primary oil. Over 700 reefs make up the northern trend and more than 300 reefs have been located in the very (EOR) processes are becoming economic in today’s environment. The natural CO2 sources come to be an excellent opportunity b are many previously considered uneconomical sequences. These marginal sections consist of highly laminated sand shale sequences alo id in the near-wellbore region forms a ring that may significantly reduce the gas relative permeability and consequently the well productivit r characteristics from an eastern Venezuela formation. Due to the complexity and number of variables involved in the process SAGD pres sis the paper also addresses the economic value of the campaign. Oil production from this field with complex geology and reservoir mecha

so imposed various damages to the oil zones. Since 2002 a joint industrial project was set up to study the feasibility of performing water s and have been an ongoing concern. The exclusion of this water represents a challenging task by itself especially in case of multiple zones i f infill wells required for field development. However they come with a disadvantage in regard to carrying out a successful intervention when ssfully applied by setting an inflatable bridge plug (TTBP) in the 6 1/8 open hole at 10 600 ft at 88 � and capping it with cement and gel u challenging in under-pressured reservoirs with openhole completions such as in the Boscan field in West Venezuela. Gravel-packed slotte and ever increasing treatment costs. It may cause major economic and operational problems for several reasons. It requires increased cap n this case is a rigless water shut-off treatment which involves an intensive process starting from candidate selection and finishing with pos oil and gas Exploration and Production Companies. Development activities in the deepwater face significant challenges.� Of particular co o characterize oil/water flow through experimental data. The tests were conducted in a 2-in. horizontal test section using tap water and min on of flow lines and wells separation and interpretation of production logs. In this study the oil/water pipe flow was experimentally investiga also accelerate the recovery.�Sensors flow-control and other devices can be used to manage the production from the commingled rese mited coordination between them sometimes bypassing important considerations from other components of the overall production system o d promote production interruption due to the formation and deposition of hydrocarbon solids such as asphaltene wax and hydrates anywhe acterization and flow assurance data. The subject of this paper is to demonstrate the importance of accurate and representative fluid charac operational expenditures since the presence of CO2 can cause corrosion failures. Carbon dioxide also denotes an issue for health safety a an extended production test may be too expensive or non feasible. Increasingly geochemical techniques are being deployed to determine

ossibly when laboratory data are not available. Correlations to estimate values of these properties have been developed that are based sole on in many applications. In this work a new set of MBO PVT correlations was developed. The four PVT functions (oil-gas ratio Rv solution tational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension but which had not been well characterized in the lab d with two downhole fluid analyzer modules helped understand reservoir fluid characteristics identify production zones and optimize perfora a are critical for reliable modeling reservoir-engineering calculations and performance predictions and for subsequent economic analysis. C ng and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/tempera e clean-up and identification of first-order impact parameters is of paramount importance for the design of new generation WFT probes tha ng reservoir compartmentalization evaluation and support flow assurance analysis. It combines known and new fluid identification sensors

½ In this paper we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in w o an NGL or GTL facility because even a tiny amount of H2S may dictate a prohibitively expensive upgrade. Detecting the presence of H2S

of a single-phase fluid. The same is true for surface sampling because of incomplete surface and/or downhole separation. Given this reality large and mistakes are costly. Compositional grading has been known for over 50 years but the topic received little attention until the 1980 . The reservoir pressure and temperature in such reservoirs are very close to the critical point and therefore small changes in reservoir con d-composition analyzer using visible near-infrared (NIR) spectroscopy. For optimal oil production assessing the spatial variation of fluid pro shore deepwater environments many reservoirs are multilayered and highly variable in terms of connectivity permeability and fluid properti e also encountered for instance due to thermal forces acting. Recognizing these behaviors downhole is a complex process that requires a d samples from openhole logging help operators optimize investment in both upstream and downstream facilities. When a formation fluid s

i 1999 Ghorayeb 2003 Fujisawa 2004 Elshahawi 2005 and Kabir 2006) that have dealt with complex fluid columns showing compositi tion spectra used to compute properties such as hydrocarbon composition and gas/oil ratio (GOR). Abrupt changes in these fluid properties and operation. Traditionally fluid information has been obtained by capturing samples and then measuring the pressure/volume/temperatu

thermal environment.� These methods were designed especially for heavy oil applications and use in numerical simulators.� The meth nt during the production of heavy oils where steam is used to reduce the viscosity of heavy oil or in cases in which submersible pumps are

limits. Also the time required on station to clean up before sampling is significantly reduced in comparison to conventional sampling metho tive samples for laboratory analyses. In order to recover uncontaminated samples fluid is first pumped out of the formation into the wellbore nvironments accurate fluid characterization becomes more critical. This can be said for the formation tester DST and multiphase sampling re of the transient evolution of flow and more accurate picture of the volumes and rates especially in cases of condensate and heavy oil en agents. Unlike HCl the reaction of organic acids with calcite is reversible and the reaction products can precipitate at certain conditions. The asses a myriad of challenges: it is a depleted (180 bars reservoir pressure at 2400 m) layered dirty sandstone reservoir with a low permeab rgely clean and undamaged (and not representative of the sandstone conditions in actual producing wells). This study proposes novel appli ave been identified which provide improved halite inhibition. Their inhibition performance was studied and compared with commercially ava

ons to understand and quantify the naphthenate-soap-deposition problem. Static bottle tests were conducted to determine the precipitation anced risk of sand production both of which are undesirable. The impact stresses fracture sand grains in the vicinity of the perforation tunne density but unfortunately it is restricted by the perforation damage zone—a region of low permeability material surrounding the perforation ability restricts fluid flow in tubing and perforation fails electric submersible and rod pumps and plugs surface equipment. Local industry off as an additive have been offered to this region. This service proved to be very effective in the Permian Basin using borate crosslinked fractu wnhole inflow control devices allow for the flexible operation of non-conventional wells.� By placing sensors and control valves at the res he upper part of the production string and Celestite or Strontium Sulphate (SrSO4) mostly found in the lower part of the production string a e stripping in a sandstone reservoir.�The formation brine composition suggests that a moderate to severe barite scaling tendency will re egions for the purpose of efficient history matching. Ideally the regions in a reservoir should be independent in terms of their effect on the o isualization of streamline-based flow pattern and injection allocation between each injector and producers. Such capability has made stream ce due to the magnitude of reserves and scale of development.� Streamline simulation brings immediate added value due to its ability to ore than 2 million stb/d in early 2000s. Field is now on decline and currently one of the major challenges is to monitor the advancing fluid le ction declined due to gas-loading backpressure and reduced permeability in the target formation. The fast decline of the gas wells during th tern floods in several gulf fields. As these new floods are established it is important to understand the water saturation between wells to pro ding the Sabiriyah Mauddud field. This effort required a new way of managing this reservoir in NK: a multifaceted approach of balancing voi th production rates ranging from 200 to 600 barrels of oil per day (BOPD) of extra-heavy oil (8�API gravity and viscosities of 2 000 cp at a ery of heavy and extra-heavy oils using thermal and non-thermal methods. Steam-based thermal recovery processes are more efficient in lo ses can be achieved by using microwave heating assisted gravity drainage.� In this study the feasibility of this method was investigated. iderable original oil in place existing in the area. Owing to the high viscosities widely different formation thicknesses and heterogeneities fou ing challenges in this area include drilling of very reactive shale’s shallow kick off depths and high build rates. Unconsolidated sandsto ing due to observed variations in oil viscosity heterogeneity related to complex mineralogy a possible dual porosity system and the presen ntaining them in single phase condition for lab analysis interval pressure transient testing (IPTT) for characterizing of permeability anisotrop

mposed of massive sandstone unconsolidated and traped very high viscous oil. Production performance of vertical wells indicates that the r

eld. An inherent problem with these wells is poor acid placement during matrix acidizing especially in reservoirs with high-permeability cont

e all classical problems due to fluid behavior met by multiphase metering device in extra heavy oil including classical separator. Heavy and

res and can result in potentially damaging precipitation reactions. In conventional acid treatments fluid is usually pumped in multiple stages chimovskaya formation of Urengoiskoe field is one of Russia’s giant low-permeability gas condensate fields. The main objectives of the

HTHP) reservoir fluids have elevated the importance of fluid properties. Like rock properties fluid properties can vary significantly both aeri

result in friction pressures that are too high and may prohibit the treatment from achieving the design goals.� With titanium (Ti) or zircon these treatments. The problem is exacerbated when treating high temperature formations and compounded with the difficulty of providing a

emperature in real time in JFYN-01 gas well. Permanent down hole system provide bottom hole pressures and temperatures during the pro with the fact that fracturing has to be performed from a vessel make the execution of fracturing treatments operationally difficult and challen le damage have been reported in these wells. Currently various formulations of mud acids organics acids and solvents are used to treat d metal in solution over time with minimal precipitation. A series of field samples from high-temperature (149�C) sandstone reservoirs in a uire continuous improvements with regards to fracturing techniques. Typically viscous polymer based fluid had being used with acceptable ng the capillary forces and enhancing the clean up of trapped water at low drawdown pressures. Five different chemicals (A1-A5) are evalu water samples collected using a formation tester and spectroscopically determining the pH in the laboratory at reservoir conditions. Water c

e (OH) completions in the Cleveland tight gas sand of the Texas panhandle. Horizontal wells have been drilled extensively in this low perme

d process enables the data and activities of multiple domains to be integrated for single-well completion optimization and field geocellular an a better understanding to the effectiveness of reservoir stimulation. Massive hydraulic fractures from two wells in the Rocky Mountain region tical importance in field development planning including well spacing pattern water injectors location that will lead to desired line drive me ville Marcellus Woodford etc.). These plays are partly technology driven and partly economics driven. Modern well log evaluation techniqu ing a range of fluids including slick water linear gel crosslinked polymers and CO2 emulsions. Most of the productive sands are associated

reasons for the success of this technique vary but the two main reasons are related to the undisputed effectiveness of hydraulic fracturing a e reservoir in the Guang’an field Xujiahe formation mainly consists of Xu-2 Xu-4 and Xu-6 formation. The lithology of the Xu-6 forma s been produced within the PNZ. As the fields mature the easy produced oil in the high permeability intervals is diminished by increasing wa luvial channel sandstones of the Upper Cretaceous Lance Formation after multistage hydraulic fracturing. Single sand body pay zones wou nomic success of wells in the Uinta Basin.� The integrated SWM involves the development of a petrophysical and a mechanical stress m ring data including hydraulic fracture data. The reservoirs consist of several sand units over a gross thickness of 4 000 ft in a fluvial deposit e in marginal tight gas reservoirs. The high cost of hydraulic fracturing increases the need for an effective and useable petrophysical model

hallenges are often found in both acquiring the adequate data and assessment of the fractures/sub-seismic faults in the oil based mud bore asing demands of various types of formation testing measurements to satisfy various reservoir evaluation objectives. Thus the complexity o han 0.1md and porosities between 3-10PU do not produce commercially. While hydraulic fracturing is widely used to improve the economic e projects. An elusive challenge has been to gather fit for purpose pressure data in these tight formations due to the nature of the rock and t

eservoir evaluation model. However acquiring this data in low permeability reservoirs can prove challenging. There is no stable flowing pres mately 2 500 m. The complex geology lack of reservoir information and lack of technology availability caused a 20-year gap between disco t require stimulation have realized sustained success with horizontal completions. One example of such success is the Cleveland Sand of n ates made up of single p.u. porosity dolomites. Prospective drilling of the territory demonstrated high heterogeneity of this formation. Prospe

ted. The measurement of mobility of the different phases throughout the transition zone which is affected significantly by complex rock hete

edium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This

ert non-monetary criteria to common monetary equivalents i.e. assigning costs allocations regarding public response to a proposed project a analysis. Nevertheless it is still one of the most common ways in which decisions are made in the petroleum company. By improving judgm ng and minimizing the geological uncertainty and maximizing or increasing the well bore exposure in the desired structure.� During the co has been obtained from special core analysis (SCAL) from a limited amount of cores due to time and cost. Rock typing is often used to help nal spatial information of reservoir characteristics. For example cores and logs have excellent vertical resolutions but very small lateral rad le. Once dual porosity is present it is found that neural network using conventional logs can not distinguish 2 rock types having the same ra ding of the sedimentary environment in the study area in Krishna-Godavari basin (KG basin) along the east coast of India. The present stud by common lateral and vertical facies changes that are responsible for uncertainties in the modeling of the reservoir heterogeneities. A reali oir fluids enables sealing barriers to be proved and compositional grading to be quantified; this information cannot be obtained from conven d with two downhole fluid analyzer modules helped understand reservoir fluid characteristics identify production zones and optimize perfora nt flow units encountered in these reservoirs. The process of identifying the flow units becomes non-trivial in the presence of extensive diag st not only because the sands within the formation are hydrocarbon bearing but also because of the complexities associated with its evalua a including neutron capture spectroscopy and capture cross section opens up new opportunities for formation evaluation on LWD. The co se sources could not be obtained with any other method. While the potential risks involved with the use of such sources have always been

urface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent net res and surface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent n at are sensitive to carbonate rock texture have led to an improved workflow for petrophysical analysis of carbonates. The authors have earlie um grained although coarser sand is common in the lowermost thick sandstone units. Both anhydrite and carbonate cements are present w lly cored interval consists of interbedded limestones and dolomites with anhydrite cement and features a wide variety of textures.� In som ness.� The reservoirs are highly permeable but the silt and clay laminations affect the reservoir permeability in each layer resulting in ch

s can provide estimates of sand resistivity and volume fraction but good results depend on the choice of the anisotropic shale point. The sa ervals. In reservoirs swept with water effects of rock electrical anisotropy on logging-while-drilling (LWD) apparent resistivity measurements he low porosity low matrix permeability and heterogeneous sedimentological characteristics of these fluvial deposits. Fracture corridors and Fluid sampling and downhole formation fluid analysis measurements also provide information for assessment of fluid complexity composit Studies identified a conundrum with respect to core and image log correlation of discontinuities: fractures and faults seen on electrical imag nd possible strati-structural traps and their associated reservoir setting. Seismic attribute analysis of 350 sq. km. of 3D seismic data of Al-Kh

ave made them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize the reservoir connectivity a per describes methods of real-time and high-resolution formation evaluation and formation testing used to characterize such reservoirs. Th tablish the hydrocarbon type and volume and finally 4) determine the permeability of the sands (as opposed to that of the sand-shale syste

ments are often considered inaccurate and therefore not as reliable for well-to-well correlations correlations with data acquired with wireline

tation around horizontal wells. Stress reorientation has been calculated for different scenarios and patterns of horizontal injection and produ s essential to analyze these problems which include wellbore stability sand production fracturing reservoir compaction and surface subsid g-induced wellbore instability. Accurate and reliable estimates of horizontal stresses can provide an early warning of impending drilling probl -rate production log measurements.� Both linear and non-linear systems are addressed in this paper providing a basis for the analysis o -rate production log measurements.� Both linear and non-linear systems are addressed in this paper providing a basis for the analysis o -rate production log measurements.� Both linear and non-linear systems are addressed in this paper providing a basis for the analysis o nvironment. The fracture systems play a significant role in production in these reservoirs and it is essential to identify areas of high fracture stand the reservoir behavior and hence assigning the best completion intervals for the producing wells. In this paper we developed a work sts mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties o ing layers subdivided into Upper and Lower Arab are fractured to varying extents. As a result a better understanding of the fracture netwo eservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservo

Array (ERA) and pressure and a production logging tool. The primary objective of this Fluid Movement Monitoring (FMM) setup and experim and attributing the properties of the produced fluid to a single reservoir fluid compartment is problematic. Overlooking the variation in fluid p has been postulated as alteration of near-wellbore formation properties during drilling operations.� The relatively tight gas sands are dril

he Bolivian Sub-Andean reveals information till now incoherent compared with core data. As it is well known when the rock does not have p or LWD petrophysical logs will guide the sample acquisition program. This typically means that resistivity and nuclear logs are used to infer igh apparent clay content. Calculated water saturations are high and need to be accurately split between clay-bound capillary-bound and f NMR logging sequences are intended to be applicable over a wide range of environments and include measurements of transverse relaxat sed. Written by individuals recognized to be experts in the area these articles provide key references to more definitive work and present mited number of cases and a solution that has field-wide applicability has been lacking. This project attempts to optimize previous results us r improved reservoir management. Conventional production logging tools cannot meet the challenges of logging horizontal wells especially

f UBD is the reduction of formation damage by minimizing the drilling-mud leakoff and fines migration into the formation. It also facilitates th ts of fine-grained packstones to wackstones that is highly bioturbated. The average thickness is about 300 ft with an average Net of 170ft in

nd facilities design as well as large errors in reserves drainage volume and production rate predictions. Downhole fluid analysis along with c DFA logs and various laboratory analyses are studied to elucidate hydrocarbon composition variations in large reservoir sand bodies. This p sing multi-rate production log measurements. Both linear and non-linear systems are considered in this work providing a basis for the anal e estimations using Pulsed Neutron Decay (PND) logging to monitor water saturation changes. Such monitoring techniques can identify inco log data and performing correlations among nearby wells proved to be inconclusive in identifying gas reservoirs owing to their thin beds hig

he need to determine the orientation and magnitude of the least principal stress. The presence of impermeable shales between producing s n. The supercharging results in an increase in sandface pressure which is above the reservoir pressure. Therefore any calculation of initial cess was an iterative multidisciplinary optimization task that generated an action plan based on multiple options developed by reservoir pro tely used to forecast reservoir behaviour hydrocarbon recovery and production. This particularly applies to marginal fields where uncertain ssures.� This can accelerate production and improve recovery. This paper outlines the workflow used for candidate screening completio pproximately 70% of the worldwide oil production. Unfortunately more often than not mature oil fields equate to high cost and low producti able to be conducted in efficient manner. These tools play an important role in well diagnostics to cater for appropriate production optimizat of stringers which are present among all the major offshore oil fields. One of the technology contributions to Saudi Aramco’s effort is pr The objective of this paper is to exemplify geosteering challenges when drilling horizontal power water injector across Permian eolian sands ears beginning in June 2000.�A total of 63 wells have been tested with well site compression; there are now 52 permanently installed co risks and uncertainties in spite of complex geological structures and drainage patterns. The new workflow encompasses planning from co ucture and fluid export schemes with capacities designed for peak production sometimes decades ago and/or different production technique telligent completions have been highlighted. A pilot well with inflow control valves (ICVs) was proposed with the goal of maximizing the well ntaneous/lifetime revenue optimization from a hydrocarbon field. This involves among others the usage of reservoir simulators surface-ne into the well.� The optimal amount of lift gas to inject into individual wells depends on a number of factors including inflow performance r in the Betty Field offshore Malaysia. The reservoirs consist of good quality sands in a coastal depositional environment with an anticlinal s ities include logging nodal analysis and well engineering technologies. Usually the older the field the more challenging to achieve addition

d reservoir model (SRM) through the set up of an integrated asset model (IAM) to validate the SRM results and control the actual production epartments. Detailed production data from many sources can be used within simulation models to give a good representation of future fiel mited coordination between them sometimes bypassing important considerations from other components of the overall production system o to conduct integrated studies successively in a continuous chain of studies as if they were on a conveyor belt.� For example field deve tion phase and challenge COPC (the field operator) with surface fluid handling capacity issues as a result of high water cuts. Additionally th

s for Khafji Field necessitated by the increase of field water cut and depletion of reservoirs.� In order to make up for production decline in clining and water production is increasing. However through reservoir surveillance data geologic and reservoir modeling significant recove he Saih Rawl field of Oman. Although the field has been producing for more than five years the results shown are based on a one-year ap Lower Vicksburg (LV) sands and the paper illustrates the key steps in the methodology. Developing Lower Vicksburg sands has been a gre price. In this case the service provider is contractually bound to provide the service at the pre-agreed price within a specified time window

magnetic tool a latest-generation LWD (Logging While Drilling) measurement was the technology differentiator for optimizing well placemen ral turbidite sandstones below a Sele shale cap rock. To maximize reserves recovery the horizontal drainholes not only had to cut as much he problem of field development where field production profile moves through successive phases of buildup plateau and decline.�This r ignificant set of calibration information early in the life of the reservoir. In this paper we describe a method for comparing a set of assumed uch fields at once.� The method is based on production engineering concepts it is very time efficient and requires only a minimum of da environment and heterogeneous geological conditions. For the last years high resolution geological models have been widely used to plan tributions: first to determine the effect of production constraints on optimal well locations and second to determine optimal well locations u perature and pressure should be maintained to improve SAGD cumulative oil recovery and the steam-oil ratio. SAGD optimization work inc sforms.�The method can be applied to calculate the pressure as a function of position and time when using any continuous function to d using a method of integral transforms. We fully account for crossflow between layers by coupling these analytic solutions together and solv cale field applications. First the CPU time increases quadratically with increasing model size thus making it computationally expensive for f ng history; second it requires large memory to save the gridblock pressure and saturation per each time step used in the forward model. Th

g the spatial reservoir parameters at grid blocks are adjusted in order to obtain a simulated response close to the observed response. This i

with steam injection and Steam Assisted Gravity Drainage (SAGD) and to simulate such models efficiently using parallel processing. The s ases or components. This type of formulation is desirable for flexibility in reservoir simulation but has not previously been used in commerc oir. This reservoir is located in an offshore field that produces oil from a relatively thin oil rim. The reservoir also contains a large gas cap tha

fficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacities. Co

ng the rate-time data and extrapolating it to predict future performance with the primary aim of estimating reservoir remaining reserves and omplex and may suffer from the presence of a yield stress non-Newtonian fluid in place and both mechanical and hydraulic damage to the llbores the gas recovery from these reservoirs is frequently unsatisfactory. Poor reservoir rock quality strong stress dependency in perme e can be used for tight reservoirs and multiple compartments or anisotropic reservoirs with high permeability contrasts. Reliable evaluations ocused on the developing efficient numerical scheme for full-field simulation and have been facing the problem of tremendous computation dding planes is possible when the effective normal stress on the bedding interfaces is low. Fracture height growth could be hindered or stop nt. The paper demonstrates the advantages of using explicit numerical simulation in contrast to analytical modeling.� Conventionally a actured well are mostly based on the work of Guppy et al. 2-6 where simple empirical correlations were developed in the form of apparent d alysis technique for multistage hydraulically fractured wells*. Based on Bayes’s theorem the new technique integrates production perfo sed rectangularly bounded reservoirs.� In particular improvements in the characterization of the dimensionless productivity index of verti of the fracture plane has initially induced significant tortuosity effects and premature proppant screenouts. The length of the perforated inte unding rock and allows for a curved path of the fracture. The model incorporates an effective finite-difference numerical method for solving mitations of using ANNs however is their poor ability to analyze small data sets because of overfitting. Several methods have been propos

amic modeling which can be summarized in the following points. First the vertical sequence of sands and shale leads to the difficulty in dete ng for both mass transfer and heat transfer between a horizontal well and a reservoir. The treatment is 1D linear in the wellbore and 1D radia iple hit on the recovery factor: Poor displacement efficiency Poor areal sweep Poor vertical sweep This is made worse by reservoir hete alized reservoirs. The drive mechanisms of these reservoirs range from strong gas cap drive to strong water influx or combinations of these l balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and accoun alling into two categories: The problems associated with the quality and quantity of initial data (ID). Very often when the development hist expression from thermodynamics of irreversible processes. The formulation and the numerical solution are used to perform initialization in n the stocks of both experimental design and response surface techniques in the E&P industry rise significantly as an alternative to the mo

he permeability tensor K(x) is allowed to have discontinuities. Transmissibility coefficients are obtained from local numerical flow experiment e “Sugar Cube19 representation of the fractured porous media. Serious spatial inhomogeneity of the saturation distribution in porous m system.� The modeling of the displacement of oil from the vugs can not be made with conventional dual porosity reservoir simulators sinc hanical data and models into reservoir characterization. The geomechanical prediction of the fracture distribution accounts for the propagat

PU times. Recently streamline simulation has been applied to fractured reservoirs at the geo-scale. However these simulations have been hich is the one used in the present work. More precisely the porosities and absolute permeabilities at each point of a reservoir are considere es with discontinuous material properties that span many orders of magnitude. Models that represent fractures explicitly as volumetric objec

roduction. Previous results reported on this project suggest that the randomized maximum likelihood (RML) method gives a biased characte

induced by temperature or pressure changes or by mixing of incompatible brines. While much work has been performed to study the effec

rted along the streamlines defined by the velocity field. The efficiency of the solution method along the streamlines is very important for the mline method for two phase compressible multicomponent flows in hydrocarbon reservoirs. We prove that even with standard PVT procedur tatistical methods or numerical simulation. Both approaches have a significant drawback; the prior being quick however very often lacking i pers have discussed reservoir characterization applications of the EnKF which can easily and quickly be coupled with any reservoir simulat permanent down-hole gauges is a recent development. A robust procedure to effectively use the enormous amount of data recorded by the ation of this model in a full-field simulator. Flow in an open or partially obstructed annulus requires looped flowpaths to be modeled within th

nsate and volatile oil) at near-critical conditions. Multiple scenario production forecasts are required to prepare an optimal development pla believed to be mixed-wet or oil-wet to some degree with a non-uniform distribution of the wettability in the reservoir.� Despite the importa

equation and whether the beta factor β for a proppant pack should be constant over the range of flow rates of practical interests. The proble e location of the free water levels. A theory applying capillary pressure scanning curves shows how changing water saturations and variatio ed by a relatively low-porosity over-pressured highly fractured and faulted carbonate. Production of the native retrograde gas condensate m wellbore pressure history and rock strength to the trajectory orientation. A stress direction map is generated for the GoS from observation he authors are neither representing the views of the SPE nor of the participants’ companies. We are delivering smarter fields in order economic climate of the late 1980-s and economic shocks during the period of well-known events in the country in 1990-s caused the rapid ssed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960’s with no oil pro o subsequently design a sealant material that will not fail under the expected conditions. The predictive models are either analytical or finite-

a heterogeneous fluvio-marine channel deposit in the Western Desert Egypt. All the wells considered in this paper showed significant wate h flow contributions still remains an issue. Several SPE papers covering the issue have been published recently. This paper presents the en in Kuwait Sabriyah Field where there are two major producing formations: Mauddud Carbonate and Burgan Sandstone Formations. The we on logging data is difficult.� Memory logging with conventional production logging tools via coiled tubing and a hydraulic tractor was em

sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the fl sampling will be high but this is contra-indicated for oils that are close to saturation pressure. A logical response is to therefore reduce the fl well in a Saudi Aramco field. Permanent monitoring of pressure and temperature enables reservoir engineers to assess the performance o que for use with wireline formation-sampling tools uses pH-sensitive dyes that change color according to the pH of the formation water. To ent bottomhole gauges has been on a surveillance and diagnostic program for over 3 years. Pressure transient analysis of shut-ins give key s microseismic monitoring campaign was to determine the overall geometry of the hydraulically induced fractures in the Canyon sandstone e must be accounted for in the creation of fracture height width and length. In many cases excessive fracture height generation is at the e

bution is understood the distribution of steam injected either at the heel or toe of the steam injector can be adjusted to optimize the startup tervals may be located in the annulus between the casing and tubing strings above the end of the tubing.� Of particular importance in thi pleted intervals may be located in the annulus between the casing and tubing strings above the end of the tubing. Of particular importance mbedded in a 1/8th inch slickline cable to calculate the inflow distribution of multi-zone gas wells with velocity strings. EnCana’s multi-z es positioning a number of different tracer materials each at specific locations along the length of lower completions prior to lowering down osis of production anomalies have been limited by sampling frequency and data quality. This paper presents field-test results of a new type

t and operational decisions may not permit the maximization of economic value and may undermine the accuracy of the reserves estimates ensitive to the wellbore inclination and the high water cut means a small proportion of the flowing liquid will be oil. At what point do these com red to very small initial gas caps in these areas. A peripheral water injection project is being considered to maintain the pressure above bub orizontal well. The field example comprises a horizontal well in the South China Sea that was completed as an openhole monobore oil prod . Moreover oil price increase promoted for technology improvement and set the unconventional techniques of the past to be conventional nd to understand the reservoir architecture. They are being used routinely in a wide range of applications spanning pressure and mobility p changes in individual layers after a well has been put on production without installing an intelligent completion or performing a multirate infl c events was recorded with signal characteristics that suggested deformation associated with thermal expansion of the wellbore in addition he different reservoir intervals limit conventional production logging possibilities so BP has chosen to install permanent fiber-optic distribute nal constraint is that sandface sensors must be deployed on a separate completion run. The objective of a recent engineering developmen ents showed evidence of thief zones in the Mauddud formation. Early water breakthrough has occurred in some wells. Previous studies ind

accurate understanding of production volumes the company’s field development and operational decisions may not support the maxim ts: 1) holdup or the cross-sectional area in the well occupied by the phase of interest and 2) velocity or the speed at which the available p

rvices suite provides the required answer by acquiring deep resistivity information through casing for subsequent formation evaluation. A tim since injection is done into formation water below oil water contact. Though the sea water front movement in the reservoir has been estima esistivity images and describe the methods employed for monitoring the fluid flow and show preliminary results of the modeling process. Thi eep efficiency identify bypassed pay and predict fluid-related issues such as water breakthrough by providing an image of the resistivity di roduction from CBM reservoirs. Wyoming’s Powder River Basin (PRB) alone has 12 000 wells in production with an estimated 50 000 m thogonal and occur perpendicular or at very high angles to the bedding. The standard suites of logs such as density/neutron gamma ray a t. High fracture pressures in coal seams coal cleating and natural fractures can lead to shear slippage and inefficient non-planar fracturing the number of wells being drilled and completed has rapidly increased. With this change in development strategy operators and service co uring.� There is growing evidence that initiating hydraulic fractures from horizontal wellbores is often difficult and requires abnormally hig well has an average of 20 pay zones that are stimulated individually. The coal cleats are fractured by pumping nitrogen at high rates throug s compared to vertical wells in the same reservoir due to the much larger hydraulic fracture surface area that is created. In order to achieve hale reservoirs. The borehole image interpretation drilling-induced fractures and conductive/healed fractures reveals stress regime orienta rough wells. Production of these reserves requires methods such as steam-assisted gravity drainage (SAGD) and cyclic steam simulation ( ed. Written by individuals recognized as experts in the area these articles provide key references to more definitive work and present speci initial hydraulic fracture stimulation treatment so that within 5 years an operator is normally faced with a well producing below its economi s to be reduced to allow wormholes to penetrate deep into the reservoir hence extending the effective wellbore drainage radius. The wormh o increase production rate from one of the offshore fields while optimizing offshore producing facilities. This offshore field has favourable co

lved as a result of extensive research and ground work. All the systems have proven their worth by increasing the productivity of the field by t into production. There emerged a necessity to develop the oil-water zones and marginal areas zones with poor reservoir properties and m ue vertical depth (TVD) of 1 400 m. The original development project for this field did not include sand control for the initially forecasted prod cementing operations. The sliding sleeve valves are opened one at a time to fracture layers independently without perforating. Completion ne with large dimensions and low layer inclinations. The main hydrocarbon accumulation is found in the Sarmatian formation (Base Cretaceo y important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required y important in this work has been the evaluation of the conditions for which the well outflow velocity is less than that which would be required ble in this reservoir.� Thus this reservoir must be exploited using horizontal wells in all areas.� In areas where fractures may not be d

he well was drilled and completed as a proof of concept. It was completed as a trilateral and was equipped with a SC that encompasses sur controlling fluids/gels and selective perforations have been used to mitigate the disparities in water encroachment over the reservoir interva Saudia Arabia. A well was drilled and completed as a proof of concept. It was set up as a trilateral and was equipped with an SC that encom

e commonplace to improve the well productivity by providing maximum reservoir contact minimizing operating costs lowering the pressure his project was to develop and apply a new concept for well completion involving ESP systems tubing-conveyed perforating (TCP) drillstem e data and permits lifetime modeling with parameter combinations employing all available data. The analysis explicitly accounts for ESPs th ed and surfactant-based have been used in an attempt to achieve optimum fracture length and conductivity.� Acids used for these treatm mpletions were considered the best completion option based on rock mechanics improved profile surveillance and cost. The original Alpine

ntana and the success there is now accelerating the transfer of technology to the North Dakota side of the Bakken trend and is attracting s ated near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sa ated by the reaction with the formation results in excessive fluid loss. Controlling fluid loss is one of the key objectives in acid fracturing trea us after initial campaign of four fracturing treatments. It demonstrated good proppant carrying capabilities and allowed decrease of polymer itives has grown. This value must be balanced with the cost of the additives which can be significant in slickwater fracturing treatments. Th is the dominant parameter controlling fracture height growth and that Young’s modulus contrast is less important. However a recent s sts per unit of gas produced. This in turn forced industry to focus on increasing efficiency by refining completion processes and field operati er to hydraulically fracture the well as well as complying with stricter governmental regulations. As produced water is recycled and used in fr nd stress state.� The application and appropriate modification of basin best practices and the application of technology for reservoir chara zuela. This technique combines stimulation and sand production control in a single treatment by placing a short and wide fracture which by arious techniques to prevent the breakthrough of hydraulic fractures into the underlying water zone but so far without clear success. The p uction rates and better access to reserves. However most of these horizontal wells are completed openhole with little alternatives for stimul d treating fluids would enter preferentially into zones with high water saturations leaving oil zones untreated with a final result of increasing oping reserves under these conditions with conventional vertical wells is in most cases uneconomical. In this setting horizontal wells have c

y successful over the past few years as the majority of the horizontal gas producers have yielded excellent results with open-hole completio

igorous process of candidate selection fracture design and implementation of fit-for-purpose technologies. 10 candidate wells were select The solution for dimensionless productivity index of a finite-conductivity vertically fractured well in a closed rectangularly bounded reservoir

ccess of hydraulic fracturing in Western Siberia organically expanded to projects in Tymen-Pechora and Volga-Urals basin. Both basins are

h normal cementing operations. The sliding sleeves were opened one at a time to fracture layers independently without perforating. The va ng sleeves would then be opened one at a time to fracture layers independently without perforating. The possibility of high fracture initiation Difficulties emerge because hydraulic fracturing in soft rock involves development of a plastic zone near the fracture surface where rocks p ous resistance of the fluid flowing through the rock matrix primarily governs fluid loss.�This has historically limited the application to fract

Sand reservoirs located in Southeast New Mexico (SENM).� The wells discussed in the paper were completed in various Morrow Sand in

hallenging due to presence of high pressure/high temperature and high asphaltene content in the crude oil which renders the situation even w discrepancies between the placed propped length and the effective production fracture length. Ineffective fracture clean-up is often cited s a clearer picture of the fracture development.� This information can be combined with other fracture diagnostic techniques and along w

e effects of the deviating borehole trajectory. For common HFM geometries a 2� deviation uncertainty of the positions of monitoring or tre

s and little lasting conductivity will be created. Despite this critical role of differential etching in the creation of fracture conductivity little is k e the recovery factor of heterogeneous reservoir developed with water flood. Three main uncertainties exist: fracture height half-length and sting tracer technology has a number of safety and environmental issues that must be addressed when using this technology as part of a fra

propped fracturing stimulations for the gas and gas-condensate wells in the Western Siberian Arctic sector. The candidate selection proce nductivity cells. At the gas velocities normally encountered in hydraulic fracture proppant packs non-Darcy pressure drops dominate and he fracture and a lag zone develops due to fluid cavitation. Properly taking into account the controlling parameters of tip behavior has resul um fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic ns of a Stimulation Index (SD) and for evaluating the efficiency of wells with low conductivity hydraulically induced fractures. We utilize the d ation of the seismic waves and injection details. Stimulation below the fault indicated a near-horizontal fracture geometry. Above the fault a wback but the physics of the phenomenon has still to be understood to predict the amount of proppant flowback during the life of a well. In re. It is shown that the propagation pressure of the orthogonal fracture quickly increases to above the closure stress on the initial fracture du placing one lowers down the displacement quality leaving most of residual viscous fluid in porous matrix. The present paper provides the da y in propped fracture dimension is related to the distribution of stresses and elastic properties as well as fluid leak off. Those factors have s

ractures although successful often underperform: Frac and Pack completions exhibit positive skin values and traditional hydraulic fractur n order to maintain the oil production target for this field the water injection rate should double the target oil rate. To achieve this water mus ose of this work is to demonstrate the benefits of applying an integrated analysis for a hydraulic fracturing evaluation that is performed using ffsets have long been recognized as sites of restricted width in the fracture channel potentially leading both to significant pressure drops an o gas lift valve designed for gas operations. The value of auto gas lift is probably easier to demonstrate than for other types of intelligent we uire sand control and this has resulted in five sandface completion types (Open Hole Gravel Pack Cased Hole Frac Pack Cased Hole Grav tured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of tured and the benefits of utilizing open-hole horizontal completion technology have been well documented. The efficiencies and benefits of ype of wells are: will it be necessary to cleanup the mud and filtercake from the openhole section before or while starting production? Will th lim intelligent completions technology has been successfully installed in Shaybah field operated by Saudi Aramco. Included in the descriptio permeability (K) variation and proximity of water traps). Furthermore conventional completions do not handle effectively heterogeneity or p ent completions are delivering better wells through improved efficiency productivity and hydrocarbon recovery with fewer wells both offshore ntelligent completions wells have been successfully installed in Abqaiq operated by Saudi Aramco. Included in the description are equipmen model-based and are effective only if the model can be used to predict future reservoir behavior with no uncertainty. Recently developed sch ss the effects of discontinuities on hydraulic fracture growth. A high viscosity fluid was used in order to provide fracture growth similar to act

rate reservoir characterization is the key to successful reservoir development. This is especially true in thinly laminated reservoirs which exh roduce the hydrocarbon. Sanding is detrimental to optimum field development and therefore information about the possible advent and ext ng deep and clean perforations may still not be enough to generate the desired productivity.� Therefore the wells are often stimulated by maximum productivity this transition requires an optimal cleanup and the removal of the perforation damages. A new underbalanced orient and E-line have difficulties. This paper presents case history of coiled tubing perforating and zonal isolation evolution in infill well at Resak f aracterized by their high permeabilities (100 - 500 md) and low pressures (1200 - 2200 psi). The wells in Anaco District are normally perfora Sea. The HZ fields are stacked thin high-permeability sandstone reservoirs interlayered with low-permeability layers. The shallower layers maximum geological stress known as the preferred fracture plane (PFP) provides significant opportunities to improve the efficiency of the f oduction. Some wells in�ADMA OPCO fields that are perforated using conventional perforating techniques�will not produce until stim nduces transient fluid flow that provides an opportunity for quantifying the formation parameters. However the skin factor can rarely be estim the accuracy of hydrostatic cushion before firing the guns. The conventional method of correlating the CT on depth involves two CT runs th erforating conditions of the perforator or perforator system is required if such damage and potential retrievability risks are to be avoided. In p

nto an outcrop carbonate rock called Indiana Limestone. Three of the tests involved shots into an outcrop sandstone rock called Berea San ellbore damaged zone. This connection through the damaged zone is usually achieved by perforating and the effectiveness of this connectio l productivity by maximizing oil production and minimizing water production. The paper will demonstrate the challenges and successes of re adients the low net-to-gross ratio the low bottomhole temperatures and the requirement for pressure maintenance. The development of the ells with 50–60� maximum hole angles. The wells are completed using dry trees from the TLP and are produced primarily from massive h field (see Figure 1) discovered in the late 1980s is located 180 km south of Riyadh the capital of Saudi Arabia (figure 1). Hawtah is one o eservoirs. Because of the long lengths of the producing reservoirs and large variations in sand-grain sizes/permeabilities premium screens w s one of the completed intervals on the S7000E horizon. Production from this interval began in April 1997 and oil recovery averaged 2000 S

olling sand and maximizing productivity it entraps the filtercake formed by the reservoir drilling fluid.� This results in low production rate at are significantly greater than expected. The success of the Greater Plutonio OHGP completions has been attributed primarily to the rigoro

during the production and the injection cycles. This challenge has a significant effect in selection of the completion technique in these wells one utilizing low-viscosity carrier fluids and low gravel concentration. In this technique the gravel is placed in two waves commonly called Alp become more common. Executing these open-hole gravel-pack jobs (alpha-beta packs) has been a challenge. Although scattered attempts considered one of the proven methods of sand control from both reliability and productivity standpoints and allows access to larger reserve conduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfo conduits between the reservoir and the wellbore for hydrocarbon production. This project presents a system approach for removal of perfor rs are planned and all will require some form of sand prevention. Extensive rock mechanical work using Statoil’s finite element modelin ection well and served as a demonstration of its potential benefits in the development of Stag oilfield. Located offshore in the North-West s or a major operator in the Gulf of Mexico. Each of the six treatments provided significant cost savings as well as excellent return on investm

significant economic loss. AGOCO recognized that it was facing a major challenge in terms of understanding potential sanding risk for Sa rs. It can impact production cause erosion in downhole and surface facilities require additional separation and disposal and lead to signifi production indicating possible sanding issues for this field. To investigate this problem relevant data from different sources and different d ry perforation-collapse tests aimed at demonstrating and quantifying the water-cut effect on perforation failure and sand production. The lab

the rock surrounding the perforations and the borehole. Sand production in weakly consolidated formations is generally assumed to be a ategies to maintain mechanical and time-dependent stabilities of extended reach wells and 2) to assess sand production risk in the develo last 4 years the application of viscoelastic surfactants was extended to acid-based systems for carbonate stimulation. These surfactants ha reatment. We conducted a series of acid fracture conductivity tests using a protocol that mimics the fluxes in a hydraulic fracture both in th n acid-fracturing treatment. Depth of penetration is controlled by the acid reaction rate leakoff and stimulation rate. Acid reaction rate is a fu eally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid deally suited for acid fracturing. During acid fracturing the wormholes created by the reaction results in excessive fluid loss. Controlling fluid onal coverage in large limestone reservoirs. The viscoelastic diverting acid system was pumped through coiled tubing in three of these wel ation permeability often exceeds one darcy. The mineralogy is composed of calcite (98 to 99%) with about 1% halite and < 1% quartz; ther -cut (WC) wells in which water has broken through as a result of high-permeability streaks or natural fractures. Furthermore acid penetratio al production gain with relatively low level of investment. In the recent acidizing campaign in Brunei a particular challenge was the flowback

y damage to each zone matrix mineralogical composition and pressure regimes of each zone need to be taken into consideration. The pr wells. The first is its high reaction rate with carbonate rocks which limits acid penetration in the formation. The second is its corrosivity to w

cated at a depth of 6100 to 7500 ft that has produced (30 to 45 �API crude) for over 35 years with production peaking at 66 000 BOPD. eating fluid over the entire interval. When fluids are pumped into a well they naturally tend to flow into the zone with the highest permeability In the mainly brown fields tertiary recovery methods such as water-flooding are implemented to maintain financial viability of the well stock. � However most previous studies reported in the literature have focused on investigating the effects of injection rate temperature and fl ssure than the previous fracture. Refracturing requirements are different in highly permeable formations (high fracture conductivity) as com the Frontier Formation located in Bighorn Basin Wyoming has seen a variety of stimulation fluids used over the past years with varying d but still not perfect. Limitations on the amount of proppant placed near water zones and formation damage from polymer residuals were the process that integrates petrophysical and reservoir characterization expertise with production and completion knowledge by developing a

ed with limited surface water handling facilities increased the importance of stimulating this type of challenging wells due to the drastic perm d are not regarded as a replacement for reservoir inter-zonal communication tests performed between producing reservoirs on every well. C eservoir pressure permeability and skin. There are two aspects of the proposed approach - straight-line analysis and modeling. A novel app this reservoir.� Thus this reservoir must be exploited using horizontal wells.� Recently a 2 270 ft long horizontal well has been drilled sient analyses and uses historical production data (rates and cumulative) and the results from production logs to; 1) determine the flow rate d as a multi-layer commingled producer then this conventional approach makes it difficult to measure the permeability and skin of individua tured formations are to prevent or delay the intrusion of unwanted fluids into the wellbore i.e. water coning.� A similar early-time pressur neous propagation of the pressure signal in the entire spatial domain when a flow rate or pressure pulse is applied to the sandface (beginni e dynamic behavior of the reservoir.� Loss of production and cost of acquiring data versus the benefits has always been a classical mana n methods to the long-standing deconvolution problem and make deconvolution a viable tool for well-test and production-data analysis. How

ze these systems based on formation properties and fluid flow behaviour such as logging and testing. Pressure-transient testing has long be expensive development plans can be put in place. New technology real time monitoring and integrated reservoir data are essential to under rvoirs are vertically heterogeneous with high permeability. MiniDST’s are conducted using the inflatable straddle packer system of wire paration and existing instrumentation is often doubtful leading to an under-estimate of liquid rates. An aggravating factor is that such wells ar he operation and the roughness of winter weather conditions combined with the complexity of the fluid compositions create unique challenge

ontrolled flow loops using idealized fluids in steady state conditions. However for high water-cut high gas-volume-fraction and low pressure oir and production management. However it can be difficult to compare data sets obtained with different measurement devices. Multiphase pretation models of traditional multiphase flowmeters emphasize the liquid rate measurements and have been used to well test and meter m for procurement actions evaluate the production test data measured by the conventional test separators and improve the testing duration a

e of device especially in the High (92-96%) or Very High GVF (96-98%) ranges. Most of the purchasers put a cut off in the GVF range of 85 dels could be used in well test interpretation. The need to effectively use information available from well test analysis in full-field simulation sure transient data [Hosseinpour-Zonoozi et al (2006)] and we demonstrate that the β-integral derivative and its auxiliary functions can be terpreted because of various artifacts collectively termed noise. While various noise-smoothing techniques have been used there are valid e streaming potentials generated by these transients were measured by arrays of permanent electrodes placed in the boreholes.�The ele

recognized as a weak spot in CO2 storage where containment can break down. This is because cement steel and elastomers can be cor grity. One principal stress is assumed vertical and of magnitude equal to the weight of the rock above calculated from the density log data. radation and casing corrosion in injection production or abandoned wells can create preferential channels over time allowing migration of C ty of oil and gas reservoirs. Optimization techniques have been applied independently to the reservoir and surface models leading to nonparse. The special behaviour of CO2-water/brine systems (mutual solubility and chemical reactivity) adds complex processes such as dry-o Federal Ministry of Education and Research and the German Federal Ministry of Economics and Technology targeted at developing an in oring them in subsurface reservoirs is thought by many scientists to be a reliable solution until emission-free energy sources are developed servoir and in its surroundings. Besides the mechanical properties of the rocks exposed to CO2 may be altered. The impact of the resulting

Reach Drilling (ERD) from a floating installation.� The 34/8-A-6 AHT2 is also the longest Down hole Instrumentation and Control System rvoirs which are poorly imaged on seismic. Reservoir overburden is fast drilling formations with hard stringers. The field pore-pressure grad

300 reefs have been located in the southern portion of the basin many of which have produced more than 5 MM bbls of oil. The EOR pote ome to be an excellent opportunity because of its low cost. Since 60 years ago 2500 km2 of carbonate formations containing CO2 were dis aminated sand shale sequences along with disbursed clay in sand. Standard cutoffs from basic log evaluation work correctly for the disburs nd consequently the well productivity.�Also when reservoir pressure drops below the dew point a big portion of condensate liquid will r involved in the process SAGD presents multiple challenges from the design and analysis phases to its final implementation. The objective omplex geology and reservoir mechanism was negatively affected by gas breakthroughs in several wells. The constraints on gas handling ca

the feasibility of performing water shutoff treatments in the open-hole completion oil wells. The study involved evaluation of a high tempera specially in case of multiple zones interval simultaneously producing and where completion of the wells restricts considerably the convoyed g out a successful intervention when water break through occurs. Water breakthrough and high basic sediments and water (BS&W) are pr nd capping it with cement and gel using coiled tubing (CT). Historically it has been difficult if not possible to perform mechanical water sh est Venezuela. Gravel-packed slotted liners and standalone premium screens are common completion methods in this field. Dual injection al reasons. It requires increased capacity of water separation and handling facilities decreases hydrocarbon production and results in large date selection and finishing with post-treatment well performance analysis. This kind of operation becomes more challenging for horizontal w cant challenges.� Of particular concern are the effects of produced fluid hydrocarbon solids (i.e. asphaltene wax and hydrates) precipita est section using tap water and mineral oil (density=0.85 g/cm3 and viscosity=15 cp) with superficial velocities ranging from 0.025 to 1.75 m pe flow was experimentally investigated for different inclination angles (0� �1� �2� and –5�). A total of 324 tests were co roduction from the commingled reservoirs and optimize the recovery. Traditional methods for production optimization and back-allocation o s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a prod phaltene wax and hydrates anywhere in the production system. These are flow assurance key risk factors that create significant impact on urate and representative fluid characterization and resulting flow assurance data on optimum facility and production method design for deve denotes an issue for health safety and the environment (HSE) and is readily absorbed by elastomer seals weakening the resistance of tho es are being deployed to determine reservoir connectivity based on the compositional differences in the reservoir fluid. In a number of reser

been developed that are based solely on commonly available field data. These properties are the dewpoint pressure of the reservoir fluid c functions (oil-gas ratio Rv solution gas-oil ratio Rs oil formation volume factor Bo and gas formation volume factor Bg) were investigate not been well characterized in the laboratory until recently. In this paper we review a gravitational gradient of asphaltenes in a reservoir and oduction zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby well or subsequent economic analysis. Compartmentalization and spatial variations of fluid composition are two primary factors that cause majo suring the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation tes of new generation WFT probes that can operate in OBM filtrate environments with enhanced efficiency. Analytical as well as numerical mo and new fluid identification sensors which allow real time monitoring of a wide range of parameters as GOR fluorescence apparent densit

ilizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections a new fo ade. Detecting the presence of H2S early in the life of a discovery can help to accurately assess the feasibility of a project and determining

wnhole separation. Given this reality the pressure/volume/temperature (PVT) analysis of any fluid sample with an equation-of-state (EOS) m eceived little attention until the 1980’s when sufficiently advanced analytical methods became available to assess the phenomenon. Ind efore small changes in reservoir condition will result in a change of fluid properties considerably. As a result there exists a broad spectrum o sing the spatial variation of fluid properties is as vital as assessing the spatial variation of formation properties. Conventional wireline triplectivity permeability and fluid properties. Such complexity and reservoir heterogeneity means conventional pressure-depth plot and pressure s a complex process that requires a greater number of data points fluid samples and associated laboratory analysis. Pressure gradients w m facilities. When a formation fluid sample is taken from a well drilled with oil-based mud (OBM) sample contamination by the OBM filtrate

lex fluid columns showing compositional gradients for columns in thermodynamic equilibrium or under steady state conditions. Montel et al. upt changes in these fluid properties with depth may be markers for reservoir compartmentalization. However hydrocarbon differences can ring the pressure/volume/temperature (PVT) properties in a laboratory. More recently downhole fluid analysis (DFA) during formation testin

numerical simulators.� The methods are based on a fluid characterized by pressure and temperature dependent K-values.� Although es in which submersible pumps are used to artificially lift the produced fluids. To efficiently design and operate heavy-oil production systems

son to conventional sampling methods. Formation-fluid sampling has always been adversely affected by mud-filtrate contamination which out of the formation into the wellbore until real-time downhole monitoring of the fluid in the tool flowline ensures it is clean. The reservoir flu ster DST and multiphase sampling and fluid characterization environments with the most challenging area in recent years arguably being th ses of condensate and heavy oil environment where traditional means of measurements are impaired by the difficulty to separate the phas precipitate at certain conditions. The precipitant may form on the rock surface and act as a barrier and ultimately stop the reaction of the ac dstone reservoir with a low permeability of approximately 15 mD containing saturated oil. The 122�C temperature complex mineralogy lls). This study proposes novel applications of straightforward chemistry to synthesize calcium carbonate particles that damage the porosity nd compared with commercially available inhibitors. Salt deposition in high salinity brines can cause blockages to production and process s

ucted to determine the precipitation rate for various pH and temperature conditions. Microscopy investigations were carried out to verify the n the vicinity of the perforation tunnel resulting in a zone of reduced permeability called the crushed zone. Additionally the impact stresses material surrounding the perforation tunnel and created by the impact of the shaped charge jet on the rock fabric. Perforating underbala urface equipment. Local industry offers a number of inhibitors to prevent scale deposition. Although regular and planned injection of inhibito asin using borate crosslinked fracturing treatments (with scale inhibitor concentrations as low as 5 gal/mgal). However these design criteria sensors and control valves at the reservoir face engineers can monitor reservoir and well performance in real time analyse data make de ower part of the production string are the common type of scales encountered in Upper ZAKUM producing wells. Injection seawater (rich in severe barite scaling tendency will require inhibitor concentrations in the range of 10-50 ppm to control scale but in practice concentrations ndent in terms of their effect on the objective function. Otherwise perturbing one variable to improve the match in a particular region may adv rs. Such capability has made streamline based history matching very attractive and more reliable in expediting history matching of simulatio ate added value due to its ability to handle high-resolution full three-dimensional models with hundreds of thousands to millions of cells inc s is to monitor the advancing fluid levels at wells and control the unexpected fluid breakthroughs. Hence the design and intelligent well man st decline of the gas wells during their first year of production drove a change from reactive into proactive management tactic to monitor the water saturation between wells to properly manage the sweep and recovery. In 2007 ADCO initiated water injection (WI) and WAG pilots to ltifaceted approach of balancing voidage with injection conducting extensive surveillance/analysis within the reservoir to assess the efficac ravity and viscosities of 2 000 cp at a reservoir temperature of 133�F). After 1995 with the implementation of horizontal drilling technolog ery processes are more efficient in low pressure reservoirs; however due to their depth the initial pressures of the reservoirs in the Faja are ility of this method was investigated.� Heavy oil samples from conceptual reservoirs (Bati Raman (9.5 API) Garzan (12 API) and Camurlu thicknesses and heterogeneities found the implementation of different thermal recovery methods is necessary. This project covers a feasi build rates. Unconsolidated sandstones and interbedded shale’s are sensitive to mud weight and are prone to lost circulation. First few dual porosity system and the presence of fractures at varying scales. This case study of the 1st Eocene reservoir characterization in the ste aracterizing of permeability anisotropy and in-situ minimum horizontal stress estimations. Pressure and fluid samples are obtained by settin

e of vertical wells indicates that the reservoirs are facing problems of low productivity bottom water conning and sand production. In his circ

eservoirs with high-permeability contrasts. Conventional acidizing results in the stimulation of water zones and misses targeted oil zones. Th

ing classical separator. Heavy and Extra-Heavy Oil represents more than 50% of the worldwide oil reserves and large efforts have been sp

s usually pumped in multiple stages of pre-flush main fluid and over flush. The drawback of conventional sandstone acidizing treatments is ate fields. The main objectives of the pilot phase of the exploration projects in the Achimovskaya formation are reducing reservoir and fluid u

erties can vary significantly both aerially and vertically even within well-connected reservoirs. In this paper we have studied the effects of gr

oals.� With titanium (Ti) or zirconium (Zr) crosslinked gels which are known to be prone to irreversible shear degradation early crosslink nded with the difficulty of providing adequate corrosion control. In addition the health safety and environmental implications of acid handlin

res and temperatures during the producing life of the well both in flowing and shut in conditions which allows to optimize production and flow nts operationally difficult and challenging. More than 60 treatments have been performed in over 40 wells placing over 3 million lbm of prop acids and solvents are used to treat these wells with mixed results. A novel chemical system has been developed for the stimulation of h 149�C) sandstone reservoirs in a West African formation bear carbonate concentrations ranging from 2% to 37% (w/w). The effects of m uid had being used with acceptable results for proppant transport and fracture placement; however these fluids are known to generate unde ifferent chemicals (A1-A5) are evaluated in this study for their ability to prevent water block formation at high temperature. Adsorption/deso atory at reservoir conditions. Water chemistry and pH are important inputs for scale and corrosion modeling. Due to the lack of standard lab

drilled extensively in this low permeability gas reservoir to enhance productivity.(5) While the increased contact area offers a potential for e

optimization and field geocellular and simulation modeling. Through this process various development scenarios for completions and drillin wells in the Rocky Mountain region were mapped in real time with a 3-D stimulation viewer software package. One well employed techniqu hat will lead to desired line drive mechanism optimized reservoir drainage and maximized recovery factor. That information is not less critic Modern well log evaluation techniques and completion methods are required to yield economic wells. In some cases microseismic monitori the productive sands are associated with nearby water sands that are often intersected by the hydraulic fractures as their heights grow whic

effectiveness of hydraulic fracturing as a production enhancement technique and the relatively low cost of pumping services in onshore area ion. The lithology of the Xu-6 formation which is the main reservoir section where the lithology mainly consists of fine-medium feldspar-qua ervals is diminished by increasing water cut. Considerable by-passed oil remains in the tighter and lower quality intervals. These oil reserves g. Single sand body pay zones would not be commercially attractive. Rigorous reservoir modeling and simulation workflows were employed ophysical and a mechanical stress model calibrated from offset nearby wells to match well production and fracturing treatments response.ï¿ ckness of 4 000 ft in a fluvial depositional environment. Reservoir rock permeabilities are in the microdarcy range. The overpressured reserv e and useable petrophysical model for an accurate productivity indication of the target interval. The pressure to avoid non-economical comp

smic faults in the oil based mud borehole environment. This paper summarizes part of the experience learned from the use of an optimal da on objectives. Thus the complexity of the wireline formation testing (WFT) has dramatically risen and continues to rise. It requires an effectiv idely used to improve the economic viability of wells and fields to that matter the presence of natural fractures plays the same role in impro s due to the nature of the rock and the granularity of the data necessary. This case study summarizes results for a wireline pressure data co

ging. There is no stable flowing pressure during the pretest build-up times can be long and the confidence level of the final pressure is often aused a 20-year gap between discovery and development. The initial pilot development was halted after poor drilling success thus the ope success is the Cleveland Sand of north Texas and the Oklahoma Panhandle. Very recently some success with horizontals has been obse terogeneity of this formation. Prospective wells drilled to this formation tests results vary from 0 to more than 600 m3 oil per day. The article

ed significantly by complex rock heterogeneity can only be accomplished by selective flow measurements. To use openhole sampling tools

s and economics of the project. This is further complicated in tight viscous and sand incursion prone formations. This paper discusses abo

ublic response to a proposed project. However this approach has many limitations related to recognizing the company’s true financial p oleum company. By improving judgment elicitation process particularly in the case of multi-criteria decision-making it is possible to improve desired structure.� During the course of drilling an 8 well Horizontal drilling program for the Kuwait Oil Company (K.O.C.) in the Burgan F st. Rock typing is often used to help map the available capillary pressure data to the reservoir layers. Borehole nuclear magnetic resonanc esolutions but very small lateral radii of investigation and the pressure transient tests have a large lateral radius of investigation but very p uish 2 rock types having the same range of porosity but different porosity-permeability relation. The dual porosity system is illustrated by stro ast coast of India. The present study aims at reconstructing sedimentary depositional environment with the help of image logs and cores an he reservoir heterogeneities. A realistic identification of the depositional environment is critical to the delineation and prediction of the best q ion cannot be obtained from conventional wireline logs. The DFA technique has been based largely on optical spectroscopy which can prov oduction zones and optimize perforation zone selection. Relying only on open hole log data and performing correlations among nearby wel ial in the presence of extensive diagenesis process affecting the original depositional texture. The conventional triple combo logs gives an a mplexities associated with its evaluation. The complexities in general relate to a heterogeneous reservoir with complex mineralogy varying w rmation evaluation on LWD. The compact design of the new-generation LWD tool greatly increases the likelihood that measurements will b e of such sources have always been known more awareness in the industry has led to increased efforts towards the reduction or even elim

ainty in reservoir areal extent net reservoir thickness porosity and hydrocarbon saturation. In this work a methodology is presented to ass ncertainty in reservoir areal extent net reservoir thickness porosity and hydrocarbon saturation. In this work a methodology is presented to carbonates. The authors have earlier described an approach to estimating permeability in carbonates from borehole NMR logs and electric d carbonate cements are present within the sandstone with the anhydrite dominating in the uppermost units. The basal sand syones are oft a wide variety of textures.� In some intervals the depositional textures are preserved in others they are highly altered by diagenesis.� meability in each layer resulting in changes in the well productivity and sweep properties. We illustrate the applications of NMR borehole im

of the anisotropic shale point. The same shale point should be used in the determination of sand porosity. Difficulties will arise when anisotro D) apparent resistivity measurements (attenuation and phase shift) could be significant. These effects need to be considered in resistivity log vial deposits. Fracture corridors and permeable fault zones also represent a major risk of water breakthrough from the underlying aquifer in ssment of fluid complexity compositional grading and acquisition of samples for input to PVT studies. Many deepwater reservoirs compris s and faults seen on electrical image logs cannot always be discerned as to whether they are of natural or drilling-induced origin. Cross-ref 0 sq. km. of 3D seismic data of Al-Khafji oil field shows number of sinuous (channel-like) events in the north and north-east of the main Khaf

racterize the reservoir connectivity and sweep efficiency. However geostatistical modeling methods do not always make an accurate infere to characterize such reservoirs. The formation evaluation of thinly bedded reservoirs has several objectives: identify the layers that may c osed to that of the sand-shale system). Formation evaluation in thin sand-shale laminations starts with their detection. NMR vertical resolut

ions with data acquired with wireline measurements and formation layer thickness determinations. The reasons for these inaccuracies gene

erns of horizontal injection and production wells. Horizontal wells are increasingly being used for production and waterflooding. Long-term in voir compaction and surface subsidence.� The mechanical parameters can be divided into three main groups viz. elastic parameters s y warning of impending drilling problems that may be mitigated by appropriate drilling fluid design and drilling practices. We have developed providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective providing a basis for the analysis of reservoirs exhibiting Darcy and non-Darcy flow respectively. Extension of the conventional Selective ial to identify areas of high fracture density. It has been observed that fractures associated with certain faults have facilitated the flow in the In this paper we developed a workflow of integrating formation micro imager Stoneley waves and petrophysical analysis for better fracture me zones. The reservoir properties of the matrix are generally negligible and the production potential of wells is mostly associated with natur understanding of the fracture networks and their relationship with major and sub-seismic faults in this field is now critical to optimize infill dri us vugs in some zones. The reservoir properties of the matrix are generally negligible and the production potential of wells is mostly associa

Monitoring (FMM) setup and experiment is to provide in-situ measurements required to determine multiphase flow properties such as relat c. Overlooking the variation in fluid properties that can and do exist in what appears to be a homogeneous reservoir on a typical log analysi he relatively tight gas sands are drilled with significant overbalance due to a mix of depleted and virgin zone layers using oil based mud sys

own when the rock does not have paramagnetic elements the porosity measured with the NMR is not affected by the minerals within the m y and nuclear logs are used to infer basic fluid types caliper log is used to verify that the borehole is suitable for sampling and NMR logs ar en clay-bound capillary-bound and free water. In addition to these reservoir characterization problems we observe effects caused by the dr measurements of transverse relaxation (T2) polarization (T1) and diffusion (D). But compromises are inevitable for any given NMR techniq o more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent adv mpts to optimize previous results using an integrated petrophysical characterization workflow. The geological complexity of the Estancia Ch f logging horizontal wells especially in multiphase flow. A new logging tool has been specifically designed to better characterize fluid flow in

to the formation. It also facilitates the possibility for reservoir characterization during drilling. The purpose of this paper is to present (1) how 300 ft with an average Net of 170ft in the upper layers. An average porosity value will be around 15% and permeability ranges between 0.00

Downhole fluid analysis along with complementary techniques including geochemical mud-gas and pressure analyses provide valuable ins n large reservoir sand bodies. This procedure was applied in the Deepwater Tahiti field in the Gulf of Mexico uncovering a large concentratio work providing a basis for the analysis of reservoirs that exhibit Darcy and non-Darcy flow respectively. An extension of the conventional nitoring techniques can identify inconsistencies leading to possible adjustments in recovery strategies and eventual improvements in ultima servoirs owing to their thin beds high shale content and variable formation water resistivity. Missing gas-bearing formations translates into

meable shales between producing sands complicates fracturing design and field development to maximize recovery. Permeability and perm . Therefore any calculation of initial pressure and permeability must take into account the supercharging effect. We present an algorithm th e options developed by reservoir production drilling and facilities engineering and ranked by economics. The process specifically involved f s to marginal fields where uncertainties such as geology (static information) and reservoir drive mechanism (dynamic information) may impa d for candidate screening completion selection and ESP system design of the first such conversion on the Bokor Field offshore East Mala equate to high cost and low productivity making mature fields unattractive when competing for resources with other options in a company†for appropriate production optimization for the field.� The Bokor field is located 45 km off the coast of Sarawak East Malaysia. The rese ns to Saudi Aramco’s effort is proactive geo-steering using Directional and Deep Resistivity technology to maximize the net sand delive njector across Permian eolian sandstone reservoirs with high degree of structural and reservoir uncertainty. The integrated reservoir manag are now 52 permanently installed compressors. The candidates were selected by testing the wells in the low-pressure area and additional kflow encompasses planning from concept selection to preparation of well proposals during the implementation work. Scalable to any given and/or different production techniques.� Substantial increases in producing gas-oil ratios and water production can occur over the lifetime with the goal of maximizing the well oil production avoiding cross-flow minimizing operational risks and well interventions(coil-tubing operat e of reservoir simulators surface-network simulators process-modeling simulators and economics packages.��� We present a co actors including inflow performance tubing and surface hydraulics.� Additionally careful consideration must be given to operating constra onal environment with an anticlinal structure terminated at the crest with a growth fault. The history match confirmed that A6.0 reservoir unl more challenging to achieve additional reserves. This paper outlines an integrated approach for achieving these opportunities reducing the

ults and control the actual production performance. A discusson of the theory of the IAM as well as the steps to set up a SRM and IAM are e a good representation of future field wide behavior. In this paper a fictional case study of a reservoir that has been producing for some 12 s of the overall production system outside of their specific domain. For example a common practice in the oil industry is to generate a prod yor belt.� For example field development planning studies for ten reservoirs some with history of more than 20 years have been genera ult of high water cuts. Additionally there are no more slots available in the existing platforms for infill drilling. Typical completions include sa

to make up for production decline in Khafji Field and to sustain the field target rate and defer large investments associated with exploration eservoir modeling significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone re s shown are based on a one-year application of a systematic approach to field optimization. This process is the dynamic integration of histo wer Vicksburg sands has been a great challenge to all operators in the region not only because of the high drilling and completion cost but rice within a specified time window regardless of the prevailing price and availability. This paper presents a mathematically consistent fram

entiator for optimizing well placement in a number of deep water horizontal wells. The new directional measurement is highly sensitive to re inholes not only had to cut as much of the good reservoir sand as possible but as the Brenda field depends on water drive as its main prod dup plateau and decline.�This results from successive drilling and commissioning of wells at a prescribed frequency (e.g. quarterly) un hod for comparing a set of assumed reservoir parameters especially the presence of a connected aquifer and its size with a set of simula and requires only a minimum of data which makes it in most cases more suitable than other methods. The approach provides a filtering c odels have been widely used to plan new wells trajectories. However the dynamic behavior of the reservoirs was widely ignored. These effe o determine optimal well locations using a gradient-based optimization method. Our approach is based on the concept of surrounding the w il ratio. SAGD optimization work includes simulation results and real-time data monitoring. Existing analytical models1 2are mainly dedicate n using any continuous function to describe the production rate of a point source. Successive integration of the point source solution can b analytic solutions together and solving for the flux field at the layer interfaces. The time evolution of these flux fields is governed by a Volter ng it computationally expensive for field applications with large number of parameters; second the sensitivity coefficients that define the rel step used in the forward model. Third it is computationally expensive as it requires solving the Adjoint system of equations backward in tim

ose to the observed response. This implies that the optimization problem can be prohibitively large and inefficient. In order to circumvent thi

ntly using parallel processing. The simulator solves component material balance energy balance and mass equilibrium equations for comp ot previously been used in commercial simulators due to its complexity and inefficiencies in both memory and speed. Here we describe an e oir also contains a large gas cap that provides the dominant energy for reservoir recovery. The reservoir is composed of interbedded shallo

s with limited platform capacities. Commonly a horizontal well trajectory undergoes undulations that may result in special wellbore flow dyna

ng reservoir remaining reserves and/or remaining productive life. The effective use of the forecast techniques: Empirical Fetkovich Locke hanical and hydraulic damage to the matrix near the fracture face. A previously published fast-and-robust single-well model was applied to s strong stress dependency in permeability hydraulic and mechanical damage caused by the fracturing process and inertial non-Darcy flow ability contrasts. Reliable evaluations of stimulation performance are required for field development planning. As such pressure transients a problem of tremendous computational resources used to simulate realistic hydraulic fracture details for better and more reliable production o ht growth could be hindered or stopped by interfacial slip when a vertical hydraulic fracture propagates in such formations. An interfacial sl cal modeling.� Conventionally analytical methods and software are used to forecast post-fracture production rates to evaluate the prof developed in the form of apparent dimensionless fracture conductivity as a function of the true dimensionless conductivity and the inertia re chnique integrates production performance data production logs and prior information to arrive at the most probable description of the res ensionless productivity index of vertically fractured wells in closed rectangularly bounded reservoirs during boundary-dominated flow have b uts. The length of the perforated interval has therefore been reduced to the acceptable minimum. Although operational problems have been rence numerical method for solving a system of coupled differential equations: 1D equations of power law fluid flow along the fracture trajec Several methods have been proposed in the literature to overcome this problem. On the basis of our study we can conclude that ANNs tha

nd shale leads to the difficulty in detecting a single gas-water contact in the field. Second the vertical heterogeneity leads to the use of fine D linear in the wellbore and 1D radial in the reservoir. A numerical algorithm for reservoir temperature calculation is proposed and an analyt This is made worse by reservoir heterogeneity. The commonly used concepts of productivity index (PI) and injectivity index (II) are not partic water influx or combinations of these. Fourteen material balance models were built and the results analyzed. This study shows that proper in oach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under ry often when the development history counts more than 20 years some well data for instance formation pressures become unavailable. n are used to perform initialization in a 2D cross section. We use both homogeneous and layered media without and with anisotropy in our c nificantly as an alternative to the more traditional uncertainty analysis. Whilst there are papers describing experimental design workflows an

rom local numerical flow experiments (transmissibility upscaling) for each cell face. Monotonicity of the solution matrix is discussed and a ve e saturation distribution in porous matrix blocks was demonstrated. Dual porosity/permeability models are obviously unable to reproduce sp ual porosity reservoir simulators since triple porosity system “isolated vugs are not part of the formulation. The simulation of oil producti stribution accounts for the propagation of fracture caused by stress perturbation associated with faults. However the challenge lies in estim

wever these simulations have been limited to two-phase incompressible systems. Commercial application of streamline methods to fractur ach point of a reservoir are considered to be those of two interpenetrating continua the matrix and the fractures one. It is also assumed that actures explicitly as volumetric objects pose a particular challenge to standard simulation technology with regard to accuracy and computatio

ML) method gives a biased characterization of the uncertainty. A major objective of this paper is to show that this is incorrect. With a correct

s been performed to study the effect of thermodynamic changes such as pressure decrease or temperature increase on scale precipitation

streamlines is very important for the overall efficiency of the method. In this work the acceleration of the saturation transport using adaptive at even with standard PVT procedures performed at each time step at each spatial point streamline technology maintain its better scaling a g quick however very often lacking in accuracy the latter being very accurate however usually very complex in setup and computation. The e coupled with any reservoir simulator. Neither adjoint code nor specific knowledge of simulator numerics is required for implementation of t mous amount of data recorded by theses monitoring systems has been proposed and tested on a synthetic case. Geostatistical simulation ed flowpaths to be modeled within the well. We describe the extension to the formulation of the well model together with considerations to en

prepare an optimal development plan for the complex. Current compartmentalization understanding based on geological and engineering da he reservoir.� Despite the importance of this parameter there is currently no proven quantitative logging technique that can provide a con

ates of practical interests. The problem was highlighted in a recent discussion by Batenburg and Milton-Tayler1 and the reply by Barree and nging water saturations and variations in levels of mixed wettability systematically control the differences in the pressures of the invading m e native retrograde gas condensate occurs primarily from three major formations: Shuaiba Kharaib and Lekhwair in the Thamama limestone nerated for the GoS from observations of borehole breakout detected in multi-arm-caliper logs and other log data base viz. electrical Image are delivering smarter fields in order to add value to our business – there are many facets to this value beyond reservoir well process an e country in 1990-s caused the rapidly decline of the number of new EOR projects. EOR technologies started to develop in direction of swee ntered the 1960’s with no oil production but by the end of the 20th century the provinces combined had delivered almost 50 billion ba models are either analytical or finite-element models. The analytical models can only be applied to relatively simple situations that require a

n this paper showed significant water production. To identify the main water-producing zones and the bypassed oil all the wells were logged recently. This paper presents the engineered solution for a TAML level 5 dual-lateral horizontal well that was drilled and completed in the O gan Sandstone Formations. The wells were completed with dual production strings due to distinct fluid and reservoir properties in these form bing and a hydraulic tractor was employed.� However due to the wear experienced by the coil high cost and poor data quality at low flo

esponse is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda forma esponse is to therefore reduce the flow rate but in wells drilled with OBM an unacceptably long clean-up time would result. The Pinda forma gineers to assess the performance of the reservoir in areas such as flood front movement and pressure support maintenance. In this well a to the pH of the formation water. To make a real-time pH measurement the dye is injected into the formation fluid being pumped through th ansient analysis of shut-ins give key performance indicators (KPIs) such as permeability-height (kh) skin (s) and current average reservoir fractures in the Canyon sandstone formation. Information and results initially derived from the microseismic interpretation were used to pro racture height generation is at the expense of fracture width and length creation. As a result in fracture treatments where excessive height

n be adjusted to optimize the startup and early operation of the SAGD pair. Total E&P Canada permanently installed optical fiber along thei g.� Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the well outf he tubing. Of particular importance in this work is the capability of determining the formation inflow profile in the well in cases where the we locity strings. EnCana’s multi-zone gas wells in the Deep Basin of Western Canada are often completed with production tubing landed completions prior to lowering downhole. The tracers are selected to be soluble in either crude oil or water. Upon well start up oil samples sents field-test results of a new type of downhole multiphase flowmeter which confirm the value of permanent downhole metering. The met

accuracy of the reserves estimates. Present digital oilfield technology gives the production engineers all the data needed to monitor proce will be oil. At what point do these compounding affects limit the ability of current technology to measure low oil flows? This paper explores t d to maintain the pressure above bubble point and improve oil recovery from the flank areas. However limited information is available conce d as an openhole monobore oil producer using a slotted liner. The well began production with an initial oil rate of 1 800 bbl/d. Oil production iques of the past to be conventional nowadays. This boom in technology application permitted high margin of investments to optimize wells ns spanning pressure and mobility profiling vs. depth fluid sampling downhole fluid analysis (DFA) interval pressure-transient testing (IPTT pletion or performing a multirate inflow performance relationship (IPR) test. This paper describes a technique allowing individual layer pres pansion of the wellbore in addition to events apparently associated with induced fracturing in the reservoir. Integration of the microseismic nstall permanent fiber-optic distributed temperature monitoring systems with its sand screens and to use these systems to monitor productio of a recent engineering development program was to create a new deployment system that directly addressed these constraints. Instead of in some wells. Previous studies indicated that it was very challenging to detect the thinly layered thief zones using conventional openhole lo

ecisions may not support the maximum economic value of the reservoir and can undermine the accuracy of the reserves estimates. With cu or the speed at which the available phase is flowing.� Recent industry developments in production logging have addressed these fundam

ubsequent formation evaluation. A time lapse saturation figure could be generated immediately after the acquisition which is extremely instru ent in the reservoir has been estimated indirectly via numerical reservoir simulator successes of direct methods have been limited by the in results of the modeling process. This crosswell EM technique which has been successfully employed and proven in other geographical area oviding an image of the resistivity distribution between boreholes in time lapse. This paper explores the influence of a high quality backgrou oduction with an estimated 50 000 more wells to be drilled in the next 10-15 years. The production rate from CBM reservoirs is low perhap ch as density/neutron gamma ray and resistivity define some of the petrophysical properties of the coal layers but the nature and extent of and inefficient non-planar fracturing which significantly underperforms the stimulation potential compared to conventional clastic rock fractur t strategy operators and service companies alike have had to search for innovative solutions to overcome challenges faced in horizontal co difficult and requires abnormally high treating pressures.� In this paper we show that the combination of high stiffness significant elastic umping nitrogen at high rates through coiled tubing (CT) into perforations isolated by straddle assembly.� Currently energy that can be de a that is created. In order to achieve optimum horizontal well stimulation the lateral section must be characterized and the perforation place tures reveals stress regime orientation fracture morphology and their orientations. The interpreted results guide the design of horizontal w SAGD) and cyclic steam simulation (CSS) (Butler 1991). �Optimal well placement defines the propagation of steam within the reservoir a re definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances a well producing below its economic threshold. To keep up with current gas demand operators have moved to an aggressive horizontal dri ellbore drainage radius. The wormholes created by a retarded acid are deep but thin. During production the flux through the thin wormhole This offshore field has favourable conditions for ESP application producing from carbonate reservoir with no anticipated fines production lo

easing the productivity of the field by many folds. But each of these artificial lift systems has economic and operating limitations that elimina with poor reservoir properties and minor reservoirs in order to maintain the production rates. Application of horizontal drilling allowed achie ontrol for the initially forecasted production rates. However the possibility of expanding the gas production rates of each well to more than 1 ntly without perforating. Completions using these casing valves are called Treat And Produce (TAP) Completions and have a unique design Sarmatian formation (Base Cretaceous Paleorelif) at the depth of 1100 to 1150 m. Currently the main productive horizons are sands from th ss than that which would be required to continuously transport and unload liquids from the well.� Sub-critical velocities are often encounte ss than that which would be required to continuously transport and unload liquids from the well.� Sub-critical velocities are often encounte areas where fractures may not be dominant it is crucial to achieve maximum reservoir contact (MRC) through the well architecture.� To t

ped with a SC that encompasses surface remotely controlled hydraulic tubing retrievable advanced system coupled with pressure and temp roachment over the reservoir interval. Recently completion technologies using downhole valves which allow production and injection contr was equipped with an SC that encompassed a surface-remotely-controlled hydraulic-tubing-retrievable advanced system coupled with a pre

erating costs lowering the pressure drawdown and maximizing profitability. This paper presents the results of a numerical study performed onveyed perforating (TCP) drillstem testing (DST) and chemical treatment of the formation by using standard equipment and techniques. alysis explicitly accounts for ESPs that are still operational at the time of the study thus removing a historical source of statistical bias. The ivity.� Acids used for these treatments have been typically formulated with 28-wt% HCl and have been used successfully to increase prod eillance and cost. The original Alpine field development plan did not include hydraulic fracture stimulation based on the reservoir characteriz

the Bakken trend and is attracting several new and existing operators to the area. Different drilling and completion techniques have been tr fracture-geometry control without sacrificing proppant-pack conductivity. The conventional approach is based on net pressure control. This key objectives in acid fracturing treatments to be able to create longer and wider fractures and hence maximize well productivity. Alternatin es and allowed decrease of polymer load without increasing risk of premature screenout. Fibers proved to be reliable for successful placem slickwater fracturing treatments. There is a range of different flowback additives containing water-wetting nonionic to amphoteric microemu less important. However a recent study pointed out that modulus contrast can have significant implications on fracture geometry and propp mpletion processes and field operations to make wells commercially viable. Strategies such as multiple-zone commingled completions the s uced water is recycled and used in fracturing applications each cycle of re-used water returns with a more complex chemical make up than tion of technology for reservoir characterization can shorten the learning curve of an operator in the development of a basin.� Numerous g a short and wide fracture which bypasses the near-wellbore damage while gravel-packing the zone of interest. This paper describes a no so far without clear success. The paper describes a technique of physical barrier placement and tailoring fracturing fluid systems to contro hole with little alternatives for stimulation water shutoff or workover treatments. A very challenging task to stimulate long openhole sections eated with a final result of increasing overall water production. However if the water production mechanism is understood and the appropria n this setting horizontal wells have come to mitigate the problem however in most unfavorable conditions where oil and gas are found in tig

ent results with open-hole completions in particular. Consequently most of the planned future wells will be drilled as open-hole horizontal c

gies. 10 candidate wells were selected and the target zone was the GS-3A reservoir. 10-15ft above the GS-3A was a water bearing sand. M sed rectangularly bounded reservoir and the corresponding pseudosteady state shape factor of this type of well and reservoir completion un Volga-Urals basin. Both basins are geologically lithologically and stratigraphically vastly different from West Siberia. Adding the difference

endently without perforating. The valves have a unique design feature which allows an unlimited number of valves to be placed in a single w e possibility of high fracture initiation pressures is identified as the main risk with this approach. This paper will discuss the theoretical an r the fracture surface where rocks partly lose their cohesion. This study has developed a more appropriate model for fracture design which rically limited the application to fracturing reservoirs with low permeabilities. A new VES fracturing fluid has been developed for use in high

ompleted in various Morrow Sand intervals around 10 500 ft with an average Bottom Hole Static Temperature (BHST) of 190oF.� Wellbo

oil which renders the situation even more difficult because of fluid incompatibility issues. The formation tends to produce oil with asphaltene ctive fracture clean-up is often cited as a likely culprit. This paper presents some of the results of an investigation of fracture clean-up mech diagnostic techniques and along with sound engineering practices can have a profound impact on how wells are completed.���ï¿

y of the positions of monitoring or treatment well surveys can cause more than a 40o uncertainty of the inverted fracture azimuths. Furtherm

ion of fracture conductivity little is known about the texture of the fracture surface created during acid fracturing or about the dependence o exist: fracture height half-length and azimuth. Commercial fracture models provide length estimate once a reliable estimate of height is know using this technology as part of a fracturing treatment. These issues along with regulations concerning the transportation of radioactive ma

ctor. The candidate selection process including production prediction is at an infant development stage and is additionally hampered by Darcy pressure drops dominate and the apparent proppant permeability is one or two orders of magnitude lower than the Darcy permeabi parameters of tip behavior has resulted in more accurate and robust fracture propagation models. However the situation is still unclear in hi ure of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stage ly induced fractures. We utilize the dimensionless productivity index solution (JD) for finite-conductivity vertically fractured wells in closed re racture geometry. Above the fault a near-vertical fracture geometry was observed. A change in fault orientation was supported by difference lowback during the life of a well. In particular determining whether the proppant flowback will stop after a few days of production or will con osure stress on the initial fracture due to the fracture penetrating into the higher stress region which leads to fracture reopening along the in . The present paper provides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic mediu s fluid leak off. Those factors have strong implication on proppant distribution especially when larger size proppant are used. Although the l

ues and traditional hydraulic fracture completions show discrepancies between the placed propped length and the effective production fra oil rate. To achieve this water must be injected into the formation at fracturing pressures. The completion campaign started with three wat g evaluation that is performed using a workflow including time-lapse Sonic Anisotropy and Flexural Waveform Dispersion Analysis (open ho both to significant pressure drops and to proppant bridging as fluid and slurry move through the restrictions. New modeling results are prese than for other types of intelligent well because it provides a direct replacement for conventional gas lift equipment compressors and pipeli d Hole Frac Pack Cased Hole Gravel Pack Stand Alone Screen and Orientated Perforating). Based on the experience and field performan ed. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple ed. The efficiencies and benefits of utilizing open-hole completion with mechanical isolation has lead to the operational benefits of multiple e or while starting production? Will the filtercake disperse and get removed while producing the well and applying drawdown to the formation di Aramco. Included in the description are equipment selection design and development details installation procedures and “lessons le handle effectively heterogeneity or permeability contrasts exposed along the sand face. The ICD controls and interrogates more optimally b covery with fewer wells both offshore and on land. Intelligent completions have proven their value in managing production from multilateral uded in the description are equipment selection design and development details installation procedures and “lessons learned after ins uncertainty. Recently developed schemes which update models with data acquired during the optimization process are computationally ve provide fracture growth similar to actual field conditions. Fracture growth and its internal fluid pressure were monitored by fixed probes place

hinly laminated reservoirs which exhibit vertical heterogeneity and a wide range of flow properties. Therefore it is critical to combine high re n about the possible advent and extent of sanding will be helpful in planning for completions and facilities. The study presented in this pape ore the wells are often stimulated by a matrix acidizing treatment after the perforating.� A prevalent mind set in the industry is that acid dis mages. A new underbalanced oriented perforating technique has been successfully implemented in Algeria. It combines the use of a format tion evolution in infill well at Resak field one of the gas field operated by Malaysia National E&P Company Petronas Carigali Sdn Bhd. Sin n Anaco District are normally perforated using conventional static underbalanced techniques. The productivity of these wells was evaluated eability layers. The shallower layers generally have better permeability and were developed first while the deeper lower-permeability reserv ies to improve the efficiency of the fracture job maximizing ultimate production from the well. Wells are frequently completed with multiple niques�will not produce until stimulated with acid.�A new perforating technique has been deployed that creates clean low skin perfora er the skin factor can rarely be estimated reliably from pressure data acquired in the current UBP operations if without flowing on surface in CT on depth involves two CT runs the first to run a memory gamma ray (GR) and casing collar locator (CCL) and the second run for the actu evability risks are to be avoided. In practice the perforating design engineers do not have a well-established analytical tool to help them und

p sandstone rock called Berea Sandstone. Four different charge types were tested including one standard (conventional) charge and three nd the effectiveness of this connection is the result of the perforating system selection the well environment in which the perforating job is e the challenges and successes of reducing produced water by using smart completions and how multiphase flow meters (MPFM) helped in aintenance. The development of the Albacora Leste Field in the ultra deep water Campos Basin was a key component of Brazil’s drive are produced primarily from massive fine-grained Pleistocene reservoirs. These reservoirs require sand control to prevent sand production di Arabia (figure 1). Hawtah is one of several small fields located along the Hawtah Trend (others are Ghinah Hazmiyah Nisalah and Umm es/permeabilities premium screens with shunt tubes in conjunction with cased-hole frac packs have been used to complete the wells. The t 97 and oil recovery averaged 2000 STB/D. Sand production was anticipated under normal drawdown from production onset and as such the

½ This results in low production rate and consequently leads to the requirement of high drawdown pressure. �Hence it is imperative that th been attributed primarily to the rigorous design and field application of the fluid systems used at all stages of the well from drilling the reserv

completion technique in these wells which require an effective and reliable sand control for long term and open-hole and large tubular siz d in two waves commonly called Alpha/Beta packing. The second method utilizes a viscous carrier fluid and high concentrations of gravel in allenge. Although scattered attempts have been made to separately understand different parts of the gravel-pack process the industry still l and allows access to larger reserves through fewer wells. Since most of these reservoirs contain reactive shale streaks they require synt stem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surg stem approach for removal of perforation damage effective gravel placement and packing of the perforation tunnels. It was found that surg g Statoil’s finite element modeling method suggests that oriented perforations can prevent sand production in the horizontal wells. This w ocated offshore in the North-West shelf of Australia Stag field is a shallow and unconsolidated glauconitic sandstone reservoir with a top an s well as excellent return on investment for the operator. Screenless completions are an integrated solution that involve many field-proven

anding potential sanding risk for Sarir and that it was necessary to design and implement a sandface completion and sand management st ion and disposal and lead to significant economic loss. On the other hand precautionary but unnecessary sand prevention will mean unwa om different sources and different domains (i.e. wireline logs laboratory test data drilling data well data and field data) were integrated to failure and sand production. The laboratory perforation-collapse tests were conducted on weak sandstones obtained from downhole and o

ations is generally assumed to be a two-step process with the shear failure being the first step and the transport of the sand out of the per s sand production risk in the development wells and eliminate unnecessary downhole sand control. The data required for the study include: ate stimulation. These surfactants have the ability to significantly increase the apparent viscosity and elastic properties of the treating fluids. xes in a hydraulic fracture both in the main flow direction along the fracture and in the fluid loss direction. In our tests the injection rate into ulation rate. Acid reaction rate is a function of several factors the most important of which is the reservoir temperature. Yet another concern excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsif excessive fluid loss. Controlling fluid loss is key to optimize acid fracturing treatments by creating longer and wider fractures. Diesel emulsi gh coiled tubing in three of these wells and bullheaded in five other wells for comparison between both methods of placement. Pre- and pos out 1% halite and < 1% quartz; therefore the formation is a potential candidate for acid stimulation. This limestone is atypical because of it ctures. Furthermore acid penetration is limited by the large surface area of the horizontal wellbore and this is exacerbated by the relatively articular challenge was the flowback of tubing pickling and spent acids and neutralization of the spent acid on the surface. A series of effec

be taken into consideration. The presence of natural fractures makes the entire treatment more complex. Acid placement and diversion ne on. The second is its corrosivity to well tubulars. Hence organic acids become viable material for matrix acidizing to alleviate these two prob

roduction peaking at 66 000 BOPD. The permeability varies from 20 to 200 mD with streaks exceeding one Darcy. At different times in the p he zone with the highest permeability or least damage. Field experiences showed that there is no assurance of complete zone coverage with in financial viability of the well stock. In many areas however production wells do not benefit enough from the water flood or the injection s of injection rate temperature and fluid properties and few have focused on the influence of rock properties on stimulation treatments.� T s (high fracture conductivity) as compared to low permeable ones (moderate fracture conductivity). Understanding these basic differences is d over the past years with varying degrees of success. When dealing with water sensitive formations a common practice has been to use o age from polymer residuals were the main drawbacks. A never ending quest for efficiency and higher production rates called for different op mpletion knowledge by developing and refining more complete interpretation and completion models based on comprehensive data. This p

lenging wells due to the drastic permeability contrast across the pay zones. Typically the treating fluid in a matrix treatment flows into high p producing reservoirs on every well. Consequently the value of continuing to run these tools was raised by management. In response the re e analysis and modeling. A novel approach is taken to develop the analytical solutions and procedures for both liquid and gas wells. Approxi long horizontal well has been drilled in an area interpreted to have high fracture density.� A comprehensive test program including flowin n logs to; 1) determine the flow rates for each individual stage in a multi-fractured well 2) apply rate-transient solutions that use rate-norma he permeability and skin of individual layers. Greater Munga field of the Greater Nile Petroleum Operating Company (GNPOC) in Sudan ha ning.� A similar early-time pressure behavior may be due to the presence of plugged perforations. Drilling problems associated with high e is applied to the sandface (beginning of a drawdown or injection) of a well. However the initial pressure propagation is not diffusive but it p ts has always been a classical management dilemma.� With the advent of digital oilfield technology the pressure and hence the deterior st and production-data analysis. However there exists no study presenting an independent assessment of all these methods revealing and

ressure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended techniq reservoir data are essential to understand such reservoirs. Another challenge presented by thinly bedded reservoirs is the presence of verti able straddle packer system of wireline formation tester. A MiniDST transient sequence consists of a single or multiple flow periods induced gravating factor is that such wells are often producing at high water-cuts thus leading to significant uncertainty on oil rates. To solve such m ompositions create unique challenges to the successful acquisition of well test data. The paper discusses the challenges and potential ben

as-volume-fraction and low pressure unstable flow these controlled conditions are far from reality which can lead to unforeseen errors in the t measurement devices. Multiphase flow meters have been proved for multiphase production metering by many operation companies world been used to well test and meter mostly liquid-rich flow streams. These models were not developed for the measurement of gas flow rates s and improve the testing duration and strategy. The program included in addition a set of elements to qualify the multiphase meters results

put a cut off in the GVF range of 85-92% following the type of technology. These criteria are often based on past experience or special cas l test analysis in full-field simulation has long been recognized. However only limited benefit could be obtained by reconciliation of the analy e and its auxiliary functions can be used to provide the characteristic signatures for unfractured and fractured wells. The purpose of this pa ues have been used there are valid concerns that smoothing procedures may adversely affect the well-test interpretation. In contrast meas placed in the boreholes.�The electrodes are partially insulated from the other completion components but nonetheless record high signa

ent steel and elastomers can be corroded by CO2 and the ageing process will be accelerated by any defects in the cement sheath. It is th alculated from the density log data. The vertical stress gradient is on average 22.01 MPa/km. Extended leak-off test data a borehole wall e els over time allowing migration of CO2 from the reservoir to shallower formations (e.g. aquifers) and/or to the surface. In this paper a risk and surface models leading to non-optimal solutions due to the non-dynamic integration between models. A recent trend of the industry is th s complex processes such as dry-out salting-out chemical reactions to the dynamic model. Simulation in these situations is one of few me nology targeted at developing an in situ laboratory for CO2 storage. Its aims are to advance the understanding of the processes involved in n-free energy sources are developed and viable.�The current options for captured CO2 utilization are; Enhanced Oil Recovery (EOR) E e altered. The impact of the resulting deformations on seal integrity must therefore be assessed in order to properly manage containment pe

Instrumentation and Control System (DIACS) installation worldwide with the lower isolation packer set at 8560 m / 28084 ft measured dep ngers. The field pore-pressure gradient is at 9.07ppg EMW but mud density needed for wellbore stability is greater than 11.6ppg. This resu

han 5 MM bbls of oil. The EOR potential of these fields is believed to be significant. Few of these fields have been waterflooded and only fiv formations containing CO2 were discovered in North of Mexico. The Quebrache region contains several occurrences of natural CO2 that h luation work correctly for the disbursed clay sections. But the cutoffs are inadequate for the highly laminated sequences; many thin high-q g portion of condensate liquid will remain in the reservoir and will not be produced. Many condensate reservoirs have been producing with final implementation. The objective of this investigation was to understand the impact of key parameters in the process specific to the selec . The constraints on gas handling capacity resulted in shutting-in a number of high GOR wells. These wells were required to be treated to s

volved evaluation of a high temperature polymer base water shut-off fluid for deep penetration of the fissure formation and a micro-fine cem s restricts considerably the convoyed down-hole tools configuration � This paper covers water shut off case history of an oil producer tha ediments and water (BS&W) are problems associated with fields having strong aquifer drive mechanisms. As a result most exploration and ble to perform mechanical water shut-off in open horizontal well as inflatables are quite sensitive to be set in open hole. This paper shows methods in this field. Dual injection combined with permanent water shutoff (WSO) gels or relative permeability modifiers to control water p rbon production and results in large amounts of produced water that need to be disposed in an environmentally friendly manner. Some field mes more challenging for horizontal wells with open hole completion. Well A a horizontal open hole producer with 2 440 ft of reservoir conta haltene wax and hydrates) precipitation and their potential to disrupt production due to deposition in the near-wellbore regions and product locities ranging from 0.025 to 1.75 m/s. Data were acquired on flow patterns pressure drop phase fraction and droplet size as a function o €“5�). A total of 324 tests were conducted in a 0.0508-m (2-in.) ID 21.1-m (69.6-ft) long test section using tap water and mineral oil with s n optimization and back-allocation of complex well configurations such as nodal analysis work only for a static problem.� They cannot the oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constr ors that create significant impact on field development planning especially when dealing with marginal deposits having varying fluid charac production method design for development of offshore fields. In this study fluid characteristics and flow assurance aspects of a live waxy als weakening the resistance of those seals and compromising the integrity of the fluid samples and the safety of equipment and personne reservoir fluid. In a number of reservoirs around the world carbon dioxide (CO2) is a critical gas composition. Examples from two such res

oint pressure of the reservoir fluid changes in the surface yield of condensate as reservoir pressure declines and changes in the specific g volume factor Bg) were investigated. According to our knowledge no other correlation for calculating oil-gas ratio exists in the petroleum li nt of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent ming correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to corre two primary factors that cause major and expensive differences between predicted and actual performance in the oil field. Furthermore diff analysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environm . Analytical as well as numerical models reported in the formation testing literature rely predominantly on simplifying assumptions in terms o GOR fluorescence apparent density fluid composition (CH4 C2 C3-C5 C6+ CO2) free gas and liquid phases detection saturation pres

M and low mobility sections a new focused sampling device was utilized for effective formation testing and sampling purity. One case history asibility of a project and determining if an offset discovery can be produced without a facility upgrade can economically make or break a pro

le with an equation-of-state (EOS) model demands that the results are verified with independent measurements. Our analyses of many sa able to assess the phenomenon. Individually geochemistry downhole fluid and mud gas analyses have provided valuable insights into com sult there exists a broad spectrum of reservoir fluids in this reservoir condition. Identifying reservoir fluid in the zones of interest is extreme perties. Conventional wireline triple-combination measurements showed that the interval of interest was uniform and free of noticeable imp al pressure-depth plot and pressure gradient analysis of wireline pressure data is not easy and identification of in-situ fluid type can be diffi tory analysis. Pressure gradients with wireline formation testers are traditionally used to evaluate fluid density fluid contacts and layer con e contamination by the OBM filtrate is a critical factor for the accurate measurement of the sample pressure/volume/temperature (PVT) prop

teady state conditions. Montel et al. (2002) discuss processes that arise from recent charging of these reservoirs which are not in equilibriu wever hydrocarbon differences can be identified reliably only when the significance of uncertainties from measurement and the oil-based m nalysis (DFA) during formation testing has provided real-time fluid information. However the extreme conditions of the downhole environme

e dependent K-values.� Although these procedures may be extended to more general N-phase systems the paper gives full details for a operate heavy-oil production systems knowledge of the realistic viscosities of the emulsified heavy oil under the actual production condition

by mud-filtrate contamination which introduces errors into the laboratory measurements of fluid properties and requires analytical methods t ensures it is clean. The reservoir fluid is then captured in sampling bottles or chambers. Gas-condensate sampling has always been the tri rea in recent years arguably being the multiphase environment. Multiphase flow meters have been accepted for several years now by the in by the difficulty to separate the phases.� Furthermore in-line multiphase flowmetering brings significant benefits to the ease of deployme ultimately stop the reaction of the acid with the rock. Recently chelating agents have been introduced as stimulation fluids. The advantage temperature complex mineralogy poor consolidation and a wide range of sources of potential formation damage make any stimulation a e particles that damage the porosity of clean sandstone cores (in core flow tests); the study includes reactions carried out under controlled c ckages to production and process systems requiring remedial action often on short notice. Current commercial halite inhibitors are only eff

gations were carried out to verify the growth of naphthenate-soap particles under different pH conditions. Core-flow tests were conducted to ne. Additionally the impact stresses plus the outward traveling shock wave severely weaken the rock matrix by de-bonding the cohesive int rock fabric. Perforating underbalanced has become the primary means of removing perforation damage and maximizing productivity tho ular and planned injection of inhibitors into producing and injector wells is the most common method of scale precipitation prevention no su mgal). However these design criteria and formulation of the scale treatments had to be changed significantly to be effective in the typical Uin in real time analyse data make decisions and modify the completion without physical intervention to optimise reservoir and asset perform cing wells. Injection seawater (rich in Sulphate) and formation water (rich in Strontium ions) mix in the reservoir and/or wellbore under varyin scale but in practice concentrations < 5 ppm are adequate.�Investigation of the produced brine compositions has revealed that this is d match in a particular region may adversely affect the match in other regions. Full independence of regions within a reservoir is not possible pediting history matching of simulation project. The objectives of the study are to improve the history match by validating fracture lineament s of thousands to millions of cells incorporating large amounts of field and well events over substantial operation periods be they historical the design and intelligent well management is key IOR option to Cantarell’s late field life management. This paper presents the result ve management tactic to monitor the field and to select candidates for workovers.� However the large number of wells in AIB (approxima ter injection (WI) and WAG pilots to test the recovery strategy. The pilot employs advanced geophysical and modeling tools to measure form n the reservoir to assess the efficacy of various courses of action and most significantly adjusting various teams’ “key performance tation of horizontal drilling technologies for the construction of wells in unconsolidated sandstones electrical submersible pumps (ESPs) be res of the reservoirs in the Faja are relatively high in the range of 600 to 1 500 psi with viscosities typically greater than 2 000 cp. For the a 5 API) Garzan (12 API) and Camurlu (18 API)) in south east Turkey were used.� Using a novel graphite core holder packed with crushed cessary. This project covers a feasibility study considering the Horizontal Alternating Steam Drive (HASD) process geared to increase the r e prone to lost circulation. First few horizontal wells were drilled with traditional technology of positive displacement motor with Silicate mud e reservoir characterization in the steam flood pilot area will improve our understanding of the range and distribution of formation properties fluid samples are obtained by setting a rubber packer and small diameter probe. The packer hydraulically isolates a small part of the forma

ning and sand production. In his circumstance CNPCIS set itself a daunting task of tripling the production in less than a year. Horizontal we

s and misses targeted oil zones. The high viscosity and low mobility of the Issran field heavy oil in contrast with the strong mobility and low

erves and large efforts have been spent to overcome difficulties related to this kind of oil production. Venezuela has pone of the largest rese

al sandstone acidizing treatments is that the success rate is generally low due to the uncertainty associated with the fluid-formation interact on are reducing reservoir and fluid uncertainties confirmation of technical and commercial feasibilities construction of a pilot gas processin

er we have studied the effects of gravity using experimental data available for five live oil and condensate systems (at high pressure and te

le shear degradation early crosslinking in the tubulars can substantially reduce the final gel strength even to the degree that near wellbore nmental implications of acid handling at surface and shortage of hydrochloric acid in certain regions must also be considered to fully apprec

llows to optimize production and flow above dew point in deep high pressure and high temperature wells where intervention is very expensiv lls placing over 3 million lbm of proppant with a success rate greater than 85%. The wells targeted were both injector and producer wells. Th n developed for the stimulation of high-temperature sandstone reservoirs. By introduction of unique chemical mechanisms the new sands m 2% to 37% (w/w). The effects of matrix treatment using a chelating agent-based system on these field samples were studied using coreflo se fluids are known to generate undesired effects such as uncontrollable height growth significant proppant pack damage lengthy clean up t high temperature. Adsorption/desorption characteristics of these chemicals and temperature stability are also investigated for long-term p ling. Due to the lack of standard laboratory techniques for such measurements at high temperatures and pressures current practice involve

contact area offers a potential for enhancing well productivity and overall well economics additional stimulation is usually required. Conven

scenarios for completions and drilling locations can be systematically and rigorously analyzed. Case studies from North America and the M ckage. One well employed techniques standard to the area –while some experimental fracture techniques were tested on the other. A gen or. That information is not less critical for infill drilling fracturing �old� wells re-fracturing fracturing of sidetracks and the knowledge o n some cases microseismic monitoring campaigns are performed in these various low permeability environments to improve the understand fractures as their heights grow which results in high water production and a subsequent significant reduction in produced gas. An integrate

of pumping services in onshore areas. Success and industry eagerness for process/cost optimization have contributed to many technologic consists of fine-medium feldspar-quartzite sand lithic feldspar-quartzite sand the pore type dominated by inter-granular small inter-granula quality intervals. These oil reserves cannot be produced efficiently and economically by vertical wells through primary or secondary method simulation workflows were employed to build a 3D flow model from geology geophysics petrophysics and engineering data and interpretat nd fracturing treatments response.� The SWM is coupled with the development of NPV optimization models for each well.� Tools for t rcy range. The overpressured reservoirs become economically viable only by hydraulic fracturing. Two major challenges of modeling the fiel ssure to avoid non-economical completions continues to leave hydrocarbons bypassed. Using recent advances in logging technology and p

earned from the use of an optimal dataset in addition to a workflow on fracture characterization for tight deep carbonate reservoirs in Kuwait ntinues to rise. It requires an effective solution to significantly reduce the largely extended rig time due to heavy WFT programs and operati actures plays the same role in improving the flow mechanics. As an industry there are many tools available which characterize the propert esults for a wireline pressure data collection campaign on twenty wells where more than 120 pressure measurements were taken in the Wa

nce level of the final pressure is often uncertain. These issues are painted on the ever-present backdrop of supercharging that can limit the er poor drilling success thus the operator invested in 3D-seismic acquisition and an integrated multidisciplinary reservoir modeling and sim ess with horizontals has been observed in the Bossier and Cotton Valley Sands of East Texas and north Louisiana. Horizontal wells are com than 600 m3 oil per day. The article describes efforts made on a new exploration approach elaboration based on an integral analysis of th

nts. To use openhole sampling tools for these flow measurements it is essential to differentiate between water-base mud (WBM) filtrate and

rmations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of

g the company’s true financial performance in comparison to quality safety environmental concerns and other factors. When nominal on-making it is possible to improve quality of critical decisions. Different technique can be used to elicit judgment from individual experts an Oil Company (K.O.C.) in the Burgan Field Kuwait it became apparent that there was a need for clearer and better quality real time log inform orehole nuclear magnetic resonance (NMR) has been demonstrated to provide pore size distribution information and methods exist in the l ral radius of investigation but very poor vertical resolution. Constructing an appropriate simulation model requires rescaling the data and th porosity system is illustrated by strong leaching (i.e. dissolution) overprinting the primary interparticle porosity of a grainstone and respons the help of image logs and cores and other available data set. Data analysis and integration of borehole images in 9 wells of the study area lineation and prediction of the best quality reservoir facies so that optimized exploitation of the reservoir can be achieved. This paper descri optical spectroscopy which can provide estimates of filtrate contamination gas/oil ratio (GOR) pH of formation water and a hydrocarbon c ming correlations among nearby wells may be inconclusive since the channel sands under study have limited lateral extent and hard to corr entional triple combo logs gives an average response when logged against diagenetically altered zone thus overlooking or under-estimating r with complex mineralogy varying water salinities across the field which makes the visualization of a conceptual geological model in the pr likelihood that measurements will be made before the onset of significant invasion. The colocation of resistivity- and neutron-based sensors s towards the reduction or even elimination of the use of chemical sources where possible. A new Logging-While-Drilling (LWD) tool has b

a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly us work a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the common om borehole NMR logs and electrical images and have earlier studied the relationship between NMR T2 distributions and capillary pressur units. The basal sand syones are often shaly and silty. The sandstone porosity value range from 9% to 26% with typical values being from 2 re highly altered by diagenesis.� Vugs are developed in several intervals.� Computation of permeability from porosity alone yields sca he applications of NMR borehole images and wireline formation testing technology in oil-base mud to evaluating the lithology the geometry

y. Difficulties will arise when anisotropy is not caused by sand-shale laminations when no sand-shale point exists or when the nearby thick eed to be considered in resistivity log interpretation. In this study LWD resistivity modeling work was conducted to study relationships betwe hrough from the underlying aquifer in horizontal wells. The identification and characterization of open fractures and conductive faults is of cr Many deepwater reservoirs comprise of young turbiditic formations which even at great depths remain unconsolidated or only weakly ceme l or drilling-induced origin. Cross-reference with cores from the same sections allows such discrepancies to be reconciled: in an example ca orth and north-east of the main Khafji Structure in Tayarat Formation of Late Cretaceous age. The present study utilizes twenty two well data

not always make an accurate inference of reservoir properties from well-logs to a reservoir model because of the stationarity and ergodicity ctives: identify the layers that may contain hydrocarbons verify productivity and fluid types with formation testing and sampling calculate n their detection. NMR vertical resolution is mainly controlled by the antenna aperture that is in the case of a high-resolution antenna 6 in. o

reasons for these inaccuracies generally originate from the traditional practice that LWD depth is purposely made equal to the driller’s d

ction and waterflooding. Long-term injection into these wells can result in the creation of fractures that grow over time. The effect of fractures in groups viz. elastic parameters strength parameters and in-situ stresses.� Even the profile of in-situ stresses with depth is estimated rilling practices. We have developed a new multifrequency inversion algorithm for the estimation of maximum and minimum horizontal stres nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and we nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and we nsion of the conventional Selective Inflow Performance analysis is also presented in this paper to obtain estimates of the formation and we faults have facilitated the flow in the Jurassic reservoirs. Identification of faults and associated fractures mainly has been on the basis of 3D ophysical analysis for better fracture characterization and selecting the best perforation intervals for a producing well. This workflow is appli wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a complete integrated eld is now critical to optimize infill drilling and produce the remaining reserves. The present paper focuses on the characterization of differen n potential of wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a compl

phase flow properties such as relative permeabilities and capillary pressures. Continuous monitoring of oil displacement by injected water i ous reservoir on a typical log analysis can lead to incorrect assumptions about the economic value of the hydrocarbon discovery the produc zone layers using oil based mud systems. To further investigate possible near formation alteration an extensive evaluation program was un

affected by the minerals within the matrix and the tool answers mainly to the contained fluids in the pores of the rock. This peculiar characte table for sampling and NMR logs are used to gauge if permeability is sufficient for a sample to be taken. However these logs are not able t we observe effects caused by the drilling process such as gas dissolution in OBM filtrate and time-lapse effects between LWD and Wirelin nevitable for any given NMR technique. For example the overall acquisition time is dictated by operating at reasonable" logging speeds so he general readership of recent advances in various areas of petroleum engineering. Introduction This summary of the state of the art in ogical complexity of the Estancia Cholita Field which is mostly due to limited lateral continuity and small reservoir bed thickness particularly ed to better characterize fluid flow in horizontal wells. Advanced sensors provide better resolution among gas oil and water and cover more

e of this paper is to present (1) how to use the inflow data for the evaluation of formation properties and (2) how to cope with the uncertain d permeability ranges between 0.001–17 mD. The oil in the Mishrif is highly viscous and production is normally enhanced by fractures in

essure analyses provide valuable insights into reservoir architecture. Each analytic method relies on different fluid traits and has its own limi xico uncovering a large concentration variation of asphaltenes. These asphaltene nanoparticles are shown to be colloidally suspended in th y. An extension of the conventional Selective Inflow Performance analysis is presented in this paper to obtain estimates of the formation an and eventual improvements in ultimate recovery. The recovery strategy for As Sarah oilfield in Libya has been based on SCAL. PND loggin s-bearing formations translates into lost productivity while perforating water zones can have detrimental effects on well performance. Moreo

ize recovery. Permeability and permeability anisotropy at different depths are unknown variables that affect well completion and reservoir m g effect. We present an algorithm that takes into account the supercharging effect in analysis of pressure transient tests acquired with a sin s. The process specifically involved first generating a series of unconstrained production options which then considered drilling reach and a ism (dynamic information) may impact significantly the estimation of reserves and result in the termination of the project during the appraisa the Bokor Field offshore East Malaysia.� A brief description of each methodology is outlined potential benefits and challenges are discu s with other options in a company’s portfolio of investments. The re-development project presented in this and its companion paper1 (S of Sarawak East Malaysia. The reservoir sands are highly unconsolidated at the top of the structure and gaining consolidation with depth.ï¿ ogy to maximize the net sand delivered from each well. The drilling of development wells in sand stringers involves very thin and sinuous ta nty. The integrated reservoir management team has utilized the geological and seismic impedance to locate a power water injector in the s he low-pressure area and additional wells highlighted by the Moving Domain study.�Compressors were installed on successful test cand ntation work. Scalable to any given size of hydrocarbon prospect and number of infill wells the computational method incorporates cross-d roduction can occur over the lifetime of the field. Falling reservoir pressures cause not only a drop in manifold pressures and the need for a well interventions(coil-tubing operations) leading to better reservoir management.� To evaluate the intelligent completion technology an kages.��� We present a comprehensive portable flexible and extensible FM framework completely decoupled from surface and s n must be given to operating constraints including cost handling capacities compression requirements and the availability of lift gas.� In ch confirmed that A6.0 reservoir unlike all others in the field which co-exist within a stacked sequence is surprisingly isolated from the surr g these opportunities reducing the risk on oil recovery associated with the various enhancement initiatives. The objectives of this paper are

steps to set up a SRM and IAM are presented in this paper. The steps are described in context of an actual field operation. A WAG cycle op hat has been producing for some 12 years will be examined. The wells are all producing into a sub-sea manifold and then tied back via a 6 the oil industry is to generate a production forecast derived from a reservoir-based model without taking into account surface facility constr ore than 20 years have been generated within one year. The three main enabling technologies for the rapid execution of integrated studies ling. Typical completions include sand-control devices such as gravel packs and fracture packs inside 9 5/8-in casing with zones separated

stments associated with exploration and drilling new wells as well as commissioning new facility expansions Production Optimization and d ural locations of clean sandstone reservoirs. As a result a comprehensive portfolio of prospects has been built for a robust development pr ss is the dynamic integration of historical data and new information technologies and engineering diagnostics to systematically identify la igh drilling and completion cost but also due to the high risk and uncertainty involved in the process. To make wise investments in such a d ts a mathematically consistent framework using decision trees conditional probabilities and Monte Carlo simulation to appropriately value f

measurement is highly sensitive to reservoir boundaries and therefore gives early warning of conditions requiring steering adjustments while ends on water drive as its main production mechanism it was essential the wells were placed as close as possible to the top of the reservoi cribed frequency (e.g. quarterly) until the total well ‘budget’ for the field is exhausted and eventual termination of wells as they reach fer and its size with a set of simulation models to assist with well placement decisions. In the South Timbalier 316 block a delineation we The approach provides a filtering concept to select all wells that might have bypassed reserves in their drainage area and provides a step voirs was widely ignored. These effects are related for instance to interference phenomena which directly impact the optimum number of in on the concept of surrounding the wells whose locations have to be optimized by so-called pseudowells. These pseudowells produce or inj ytical models1 2are mainly dedicated to describing the ability of a reservoir to drain heated oil and do not depict all details of real SAGD pro on of the point source solution can be performed to calculate the average bottom hole pressure of a well. These equations are applicable se flux fields is governed by a Volterra integral equation. Within a multiple layer reservoir scenario our semi-analytical solutions are applicab sitivity coefficients that define the relationship between reservoir properties and the production response typically depend on either the numb system of equations backward in time per each forward time step which is usually of high magnitude in case of field scale applications of lon

nefficient. In order to circumvent this problem a set of multiple geologically plausible permeability realizations or the training images for a g

mass equilibrium equations for component mole fractions saturation temperature and pressure using the Newton-Raphson method. Externa y and speed. Here we describe an efficient natural-variable-based general formulation approach which handles general partitioning of phas is composed of interbedded shallow marine-ridge sands with some coarsening-up sequences. A typical horizontal well in this field has pe

y result in special wellbore flow dynamics. In addition technologies such as intelligent completions can be used to regulate flow from variou

niques: Empirical Fetkovich Locke & Sawyer and Analytical Transient solutions for oil and gas wells/Reservoirs using a production surveil st single-well model was applied to study the important parameters involved in the fracture-cleanup process. This three-phase 2D model pro process and inertial non-Darcy flow effects were considered to be key parameters for poor performance in previous studies. A further one ning. As such pressure transients are often used and can be successful tight reservoirs where transient flow regimes can be used to obse better and more reliable production optimization. Most of the existent numerical models are based on 3D computational grid that is used for in such formations. An interfacial slip model has been developed and implemented in a pseudo-three-dimensional (P3D) hydraulic fracture production rates to evaluate the profitability of fracturing. The availability of analytical software that is simple and fast has been the rational onless conductivity and the inertia resistance factor. However based on the parameter matrices of their numerical analysis restrictions were most probable description of the reservoir/completions. After validating results with a numerical reservoir simulator we systematically used ng boundary-dominated flow have been made using a mathematically rigorous model for pseudosteady state flow.� This model has been ugh operational problems have been solved this way the net pressure response while successfully fracturing did not obey any of the existin aw fluid flow along the fracture trajectory and 2D equations of the linear elasticity for rock massif. The model predicts and evaluates the nea udy we can conclude that ANNs that use radial basis functions (RBFs) can decrease the error of the prediction effectively when there is an

eterogeneity leads to the use of fine gridding especially in the vertical direction to accurately simulate the fluid flow in the reservoir. Third the alculation is proposed and an analytical solution is derived on the basis of some realistic assumptions. The analytical solution can be used t and injectivity index (II) are not particularly useful when the mobility ratio is high since they require the use of a nominal drainage radius whe zed. This study shows that proper integration of all pressure production and geological data is critical in defining reservoir compartmentaliza material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir en ion pressures become unavailable. Well logs and well tests can be missing if not properly archived. Moreover the data may be complete without and with anisotropy in our calculations. Numerical examples for a binary mixture of C1/C3 and a multicomponent reservoir fluid are g experimental design workflows and the different methods of generating response surface models for reservoir simulation studies there is

solution matrix is discussed and a version of the method that provides an M-matrix is described. Convergence and numerical flux consistenc re obviously unable to reproduce spatial condensate distribution in near wellbore zone of the reservoir but after proper tuning these models ation. The simulation of oil production from triple porosity reservoirs requires the development of composite porosity composite relative pe However the challenge lies in estimating the past remote stress conditions which induced structural deformation and fracturing the limited

ion of streamline methods to fractured reservoirs often requires the modeling of at least three compressible fluid phases. Flow simulation o actures one. It is also assumed that the flow occurs in fractures only i.e. the matrix permeability is equal to zero. Mass transfer between m h regard to accuracy and computational efficiency. We present a new simulation approach based on streamlines in combination with a new

that this is incorrect. With a correct implementation of the RML method within a Bayesian framework we show that RML does an adequate

ature increase on scale precipitation it is only recently that a body of work has been developed on the impact that the dynamics of brine mix

e saturation transport using adaptive mesh refinement (AMR) along streamlines is investigated. The refinement strategy is based on the mu hnology maintain its better scaling ability than traditional finite difference/volume technologies. However we went further and have treated t plex in setup and computation. The presented workflow is a new approach to infill well performance prediction that combines speed and re cs is required for implementation of the EnKF. Moreover data are assimilated (matched) as they become available; a suite of plausible rese etic case. Geostatistical simulations involve generating multiple equi-probable fine scale depictions of the reservoir heterogeneity each ho del together with considerations to ensure that the resulting equations have a Jacobian matrix that is invertible and explain the necessary mo

ed on geological and engineering data led to 24 isolated segments for which up to 24 separate simulation models can be potentially built. B ng technique that can provide a continuous wettability log. A detailed analysis of a new model for the conductivity of reservoir rock called the

Tayler1 and the reply by Barree and Conway2 regarding paper SPE 893253 in the JPT in August 2005. To properly assess all the argumen es in the pressures of the invading mud filtrate and formation oil to result in the following unusual yet often observed behavior: 1) negative Lekhwair in the Thamama limestone. Commercial production from the field commenced in late 1984 with good performance being attribute log data base viz. electrical Images and sonic logs. In vertical wells the maximum tangential stress around borehole can produce breako e beyond reservoir well process and production management.�What may not be so clear is how to apply these smart technologies to arted to develop in direction of sweep efficiency improvement by cheap agents. Nevetheless by now the very intereresting EOR experience d had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States. Alaska’s North Slope started pr vely simple situations that require a simplified set of input data. In these cases the results are consistent with those of finite-element model

passed oil all the wells were logged using a through-casing formation resistivity tool. One well was also surveyed with pulsed neutron captu t was drilled and completed in the Oseberg S�r field in December 2005. The solution combines hydraulic flow control valves with advanc and reservoir properties in these formations. Water injection was implemented in Mauddud Formation in late 2000 after a successful waterf cost and poor data quality at low flow rates this technique was abandoned after initial logging efforts. Development of a state-of-the-art ele

time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low doub time would result. The Pinda formation in Block 2 offshore Angola presents just such a challenge. Formation mobilities are in the low doub support maintenance. In this well a multi-reservoir dual gauge system was deployed to monitor pressure and temperature in two stacked ca mation fluid being pumped through the tool flowline and the relevant visible wavelengths in an optical detector are used to record the dye sig n (s) and current average reservoir pressure (Pave); the KPIs are summarized on a quarterly basis and compared with historical trends to c smic interpretation were used to provide the operator with recommendations for reservoir management such as drilling patterns new well p treatments where excessive height growth is believed to have occurred premature screenouts are usually the result of insufficient fracture

ently installed optical fiber along their first Joslyn SAGD production well to monitor the temperature profile continuously during startup and p the well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well.� Sub le in the well in cases where the well outflow velocity is less than that required to continuously transport and unload liquids from the well. Su pleted with production tubing landed near the lowest perforated interval to act as a velocity string and lift produced water to surface. This co ater. Upon well start up oil samples are taken at the surface over a short period of time. These samples are analysed to determine tracer pr manent downhole metering. The meter contains only three sensors but is capable of direct multiphase-flow-rate and cut measurements witho

all the data needed to monitor process parameters and fluid production under the assumption that deviation from any target would be detec low oil flows? This paper explores this question by analyzing production logs from wells with water cuts as high as 99%. The horizontal wel imited information is available concerning Wara reservoir heterogeneity. Shut-in of all Wara producers provided an “once-in-a-lifetime op oil rate of 1 800 bbl/d. Oil production quickly dropped to 1 000 bbl/d and gradually declined to 200 bbl/d. During this period the gas oil ratio ( gin of investments to optimize wells/fields production and gave production/reservoir engineers a good hand in obtaining better data for dec rval pressure-transient testing (IPTT) and microfracturing. Because of the complex tool strings and the elaborate operational aspects involv hnique allowing individual layer pressures or gas/oil ratios (GOR) to be monitored continuously during production. The technique employs voir. Integration of the microseismic data with volumetric strain inverted from the measured surface deformation indicates a discrete deform these systems to monitor production rates and changes over time. The optic fiber has been installed on the periphery of the sand-screen essed these constraints. Instead of individual gauges on mandrels digital sensors were miniaturized and distributed along a single spoolab ones using conventional openhole logs. This paper describes a methodology of recognizing the different types of thief zones in the Mauddu

y of the reserves estimates. With current Digital Oilfield technology it is possible to measure production volumes at the well level and at inte gging have addressed these fundamental requirements of measurement with multiple probe technology that differentiate between Oil Holdup

acquisition which is extremely instrumental to take an immediate decision. The technology is well known in the industry and already proven methods have been limited by the injection volume and environmental effects. Direct spatial measurement of the injected sea water front w nd proven in other geographical areas is being implemented first time in UAE. The EMI technology is being deployed in southern part of a c influence of a high quality background geologic model in constraining the interwell results and providing a higher resolution image of the on from CBM reservoirs is low perhaps 50-100 mcf/day. Various completion methods are being evaluated and new technologies are being de l layers but the nature and extent of cleating often remains poorly defined from these logs and by using standard log evaluation methods. A d to conventional clastic rock fracture stimulation. In 2003 the concept of indirect fracturing was introduced to significantly increase Coalbed me challenges faced in horizontal completions. Inefficient fracture initiation is the largest reoccurring problem encountered when completing n of high stiffness significant elastic anisotropy and coupled elastic property and horizontal stress development in tight gas shale reservoi .� Currently energy that can be delivered to the coalface of these dry CBM wells has been limited by the friction pressure through (CT). E aracterized and the perforation placement customized to account for reservoir changes along the wellbore.� In most cases evaluation is l ults guide the design of horizontal wells to control hydraulic fracture directions and intensities. Conventional logs and cores have been used ation of steam within the reservoir and the resulting flow of crude. SAGD recovery methods require tremendous amounts of steam in order neral readership of recent advances in various areas of petroleum engineering. Introduction Annual natural-gas production from coalbedoved to an aggressive horizontal drilling and completion program.� Additionally in an effort to increase the productivity of existing wells a n the flux through the thin wormholes can be so high that high pressure gradient occurs. Therefore the optimized wormhole geometry shoul h no anticipated fines production low GOR low temperature low bubble point pressure and high API gravity. All new installations were car

nd operating limitations that eliminate it from consideration under certain operating condition. However all the conventional artificial lift syste n of horizontal drilling allowed achievement of the above tasks.� Horizontal completions resulted in not only enhancement of individual w ion rates of each well to more than 1 MMm3/D �increased the associated sand production risk and led to the need for evaluating� the mpletions and have a unique design feature in the valves that allows a theoretically unlimited number of valves to be placed in a single well oductive horizons are sands from the lower Sarmatian (Basal Sarmatian). The facies variation can be seen both vertically and horizontally o -critical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly -critical velocities are often encountered in low productivity gas wells that produce liquids whether the wellbore liquids are produced directly hrough the well architecture.� To this end a tri-lateral MRC well with a mother bore and two laterals has been recently drilled in this reser

em coupled with pressure and temperature monitoring system. The SC provides isolation and down hole control of commingled production allow production and injection control over multiple zones have become available. The central idea is that downhole control may be used t advanced system coupled with a pressure- and temperature-monitoring system. SC provides isolation and downhole control of commingled

ults of a numerical study performed to determine the production performance of dual opposed laterals compared to horizontal wells. With a andard equipment and techniques. The concept was developed after identifying the opportunity to optimize operations in wells where the ab orical source of statistical bias. The analysis uses Kaplan-Meier (KM) (Kaplan and Meier 1958) and Cox proportional hazards (CPHs) (Cox n used successfully to increase production from the Khuff carbonates. Although acid fracture treatments create significant conductivity enh n based on the reservoir characterization. Well performance had proven to be economic in this Jurassic marine sandstone without hydrauli

completion techniques have been tried since the start of the play with different degrees of success. In June of 2005 a new technique was in based on net pressure control. This can be achieved using low-viscosity fluids such as viscoelastic systems oil-based systems or reduced maximize well productivity. Alternating stages of polymer pad with diesel emulsified acid for deeper penetration and in-situ gelled acid a poly to be reliable for successful placement of 10/14-mesh size Intermediate Strength Proppants (ISP) at concentration up to 1000 kgPA and hig g nonionic to amphoteric microemulsion and oil-wetting components. Determining the best additive for a specific reservoir is not a simple ions on fracture geometry and proppant placement (Smith et al. 2001). To expand on this topic we consider the combined effects of modulu zone commingled completions the selection of fluids and additives to maximize hydraulic fracture effective length and conductivity and flui ore complex chemical make up than before. Therefore the usable lifetime of the recycled water is shortened or requires expensive cleaning elopment of a basin.� Numerous completion strategies (Limited Entry high rate limited entry and various Pin-point Stimulation Techniqu interest. This paper describes a novel and economical frac-and-pack technique which consists of pumping a sand plug with the downhole ng fracturing fluid systems to control fracture net pressure development that combined is used to mitigate fracture height growth. The meth to stimulate long openhole sections effectively due to poor acid distribution especially in reservoirs with high permeability streaks that requir sm is understood and the appropriate fluids are selected then stimulating producer wells with high water cuts can be a rewarding operatio ns where oil and gas are found in tight formations fracture stimulation needs to be added to the equation. Conventional multistage fracturing

be drilled as open-hole horizontal completions. Nonetheless due to the highly complex nature of the Khuff carbonate reservoir some wells

GS-3A was a water bearing sand. Most of the candidate wells were primarily in an area of the reservoir that had experienced poor recovery of well and reservoir completion under boundary-dominated flow conditions has been developed and utilized in this study. The mathematic

West Siberia. Adding the difference in the maturity of the fields with significantly depleted reservoirs high asphaltene and paraffin oil conten

r of valves to be placed in a single well without incremental reductions to the ID thus allowing normal cementing operations. A control line is paper will discuss the theoretical and experimental study that was conducted to assess the viability of the cemented sliding sleeve concept ate model for fracture design which takes into account processes in the plastic zone for the special case of soft rock that is a cohesionless has been developed for use in high permeability reservoirs and successfully pumped in the Gulf of Mexico.�The fluid exhibits enhanced

rature (BHST) of 190oF.� Wellbore completion constraints combined with reservoir parameters inclusive of low-pressured water sensitive

tends to produce oil with asphaltene content when the flowing bottomhole pressure is drawn below the Asphalting Onset Pressure (AOP). A estigation of fracture clean-up mechanisms. This investigation was undertaken under a Joint Industry Project (JIP) active since the year 20 w wells are completed.������ This paper discusses the completion design methodology execution and results from two o

nverted fracture azimuths. Furthermore if the positions of the injection point and the receiver array are not known accurately and the veloci

acturing or about the dependence of this texture on the acidizing conditions. To study this important aspect of the acid-fracturing process w e a reliable estimate of height is known. This is evident for 2D model which requires a direct knowledge of the height but also for p3D model the transportation of radioactive materials have impacted the application of this technology in international markets. This paper will describ

ge and is additionally hampered by the lack of or ambiguity in the reservoir and production data. This is particularly true for the Yamburg ude lower than the Darcy permeability measured at single phase low-rate conditions. This is particularly true if a liquid phase is also flowing ver the situation is still unclear in high permeability formations because the formation fluid can invade the tip zone where the pressure dro pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressur vertically fractured wells in closed rectangular bounded reservoirs and their corresponding pseudo-steady state shape factors under bounda entation was supported by differences in the microseismic-signal characteristics and the treatment-injection data. This difference in fracture a few days of production or will continue at a given rate during the well's life is a key issue when selecting an appropriate completion metho ds to fracture reopening along the initial fracture plane (called in-plane frac hereafter). A dual-frac PKN model is developed to predict the gr damages in elastoviscoplastic medium as well as the effect of inhomogenity of porous media properties on fracture propagation. After hydra e proppant are used. Although the latter could lead to more conductive fractures they could also bridge at the wellbore impeding both later

ngth and the effective production fracture length. Ineffective fracture clean-up is often cited as a likely culprit. The main results presented ion campaign started with three water injector wells. The initial results were not as expected i.e. after pumping 1000 bbls of treated seawat veform Dispersion Analysis (open hole and cased hole) which main objectives consisted on the generation of a horizontal stress map for the ons. New modeling results are presented that quantify these and other effects of offsets by using a coupled 2D hydraulic fracture model. Of equipment compressors and pipelines and the ancillary equipment they require. An estimated 60 auto gas lift systems have been installed n the experience and field performance open-hole gravel packing has become the preferred option. The techniques used in completing thes the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficien the operational benefits of multiple fracturing operations being pumped in one continuous operation equating to time savings more efficien applying drawdown to the formation? Will the remaining filtercake impair well productivity? The paper presents the case of a gas producin ation procedures and “lessons learned after installation of the fully hydraulic tubing-retrievable advance completion system with digital p s and interrogates more optimally both rock and fluid properties in the reservoir hence delaying early water breakthrough. This early water anaging production from multilateral wells horizontal wells with multiple zones and wells with heterogeneous reservoirs using a single wellb s and “lessons learned after installation of the fully hydraulic tubing-retrievable advanced completion system with digital permanent dow ion process are computationally very expensive. We suggest that simple reactive control techniques triggered by permanently installed do ere monitored by fixed probes placed normal to the expected plane of propagation. Fracture tip arrivals were captured by the fixed pressure

efore it is critical to combine high resolution formation evaluation logs and formation tests to predict the well performance prior to the produ es. The study presented in this paper characterizes the geomechanic behavior of a field in which sanding problems are expected after depl ind set in the industry is that acid dissolves the perforation debris and creates wormholes that bypass the perforating and other near wellbo eria. It combines the use of a formation isolation valve (FIV) to keep damaging completion fluid off the formation immediately after perforatio ny Petronas Carigali Sdn Bhd. Since the beginning of Resak Field production coiled tubing has been used to perforate numbers of infill w ctivity of these wells was evaluated using nodal analysis techniques coupled with perforating performance simulations. The quality and amo e deeper lower-permeability reservoirs have been developed more recently. The lower-permeability reservoirs are generally of lower poros frequently completed with multiple tubing strings (up to four in some cases) sensor lines control lines or other hardware that can be dama that creates clean low skin perforations�and allows the well to be produced at commercial rates while waiting for the multipurpose barg tions if without flowing on surface in sufficient time. The reasons are that (a) the flow rate after an UBP continuously varies during the surge CCL) and the second run for the actual perforation. The underbalanced condition calculated based on wellbore fluid displacement is often de shed analytical tool to help them understand post-perforating behavior of perforators. They have to rely on their own experiences and previo

dard (conventional) charge and three different designs of reactive liner charges. Among all charges the only difference of note was the desi ment in which the perforating job is executed and what happens to the perforations after shooting and before they are used for production or hase flow meters (MPFM) helped in getting better results to allow faster decision making. In one of the challenging areas in Ghawar field wh key component of Brazil’s drive to achieve petroleum self sufficiency by 2006. Because of the challenges presented by the heavy oil a d control to prevent sand production at the expected drawdowns planned during the life of the wells. To help ensure high-rate long-life com hinah Hazmiyah Nisalah and Umm Jurf). The Trend runs approximately 30 km east to west and 50 km north to south. Production in Hawta n used to complete the wells. The third well A1ST1BP1 was completed using the same techniques as were used successfully on the first om production onset and as such the well was completed with sand-control measures in place. After about ten years of production a signifi

ure. �Hence it is imperative that the filter cake be removed uniformly to ensure lower drawdown pressure and even flow distribution throu es of the well from drilling the reservoir through to the gravel pack itself and subsequent completion. An integrated approach was adopted fo

and open-hole and large tubular size to minimize friction losses. Until now standard open-hole gravel packing was the common completion and high concentrations of gravel in conjunction with alternative path screens which mitigate problems caused by unpredicted downhole ev avel-pack process the industry still lacks a tool that accurately models the complete process and aids in successfully designing these jobs. tive shale streaks they require synthetic/oil-based drilling fluids (S/OB). Considering that the openhole gravel packing in the industry deals ration tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the conn ation tunnels. It was found that surging the perforations greatly increased the ability to pack the perforation tunnels and improved the conne duction in the horizontal wells. This was offered as an alternative to mechanical sand control in the long horizontal wells due to traverse sev tic sandstone reservoir with a top and bottom sealing shale. The reservoir pressure is low and it contains heavy and viscous oil of 19� AP ution that involve many field-proven technologies such as reservoir characterization perforating coiled-tubing intervention matrix acidizing

ompletion and sand management strategy for more than 400 wells in the field. It was decided to apply a particular systematical approach te ary sand prevention will mean unwarranted reduction in productivity. Reliable sanding prediction analysis thus provides a basis for designs ta and field data) were integrated to generate a Mechanical Earth Model (MEM). This model provided the descriptions of the rock strengths ones obtained from downhole and outcrop. The tests were performed under simulated in-situ effective stresses and drawdown conditions. W

transport of the sand out of the perforations and up to the surface being the second step. Existing sand production prediction models hav e data required for the study include: 1) in-situ stresses including magnitude and orientation and formation pressure 2) mechanical and pe stic properties of the treating fluids. This is because of the ability of surfactant monomers to associate and form rod-shaped micellar structu n. In our tests the injection rate into the fracture is much higher than in many previous tests and the fluid loss flux is controlled to match fie ir temperature. Yet another concern in acid fracturing in long carbonate intervals is attaining the necessary diversion to ensure that multiple and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exc r and wider fractures. Diesel emulsified acid for deeper penetration and in-situ gelled acid a polymer-based system are used to control exc methods of placement. Pre- and post-job production logs acquired in five wells provided analysis of changes in the production profiles. In o is limestone is atypical because of its texture—a granular aggregation of carbonate particles poor cementation and a moderate-to-low ro this is exacerbated by the relatively small injection rate imposed by the use of coiled tubing (CT). To make matters worse formation damag acid on the surface. A series of effective methodologies for the stimulation of offshore multi�layer sandstone oil reservoirs was implement

ex. Acid placement and diversion need to be carefully designed and optimized to effectively stimulate the wells by reducing the skin factor t acidizing to alleviate these two problems. Though organic acids provide the benefit of retardation and low corrosivity their low dissolving ca

one Darcy. At different times in the past attempts were made to hydraulically fracture one or more of the sands using a variety of different ance of complete zone coverage without proper diversion. Therefore diversion is recommended in all treatments especially in extended rea om the water flood or the injection scheme is not optimized.� A consequence of reservoir pressure depletion is the increase in filtrate lea rties on stimulation treatments.� This study primarily explores the influence of pore scale heterogeneities on stimulation treatments.� S erstanding these basic differences is essential to a successful restimulation. In the past candidate selection methodology has focused on u common practice has been to use oil-based fluids. However fluids of this nature can have detrimental effects on gas zones with low reserv oduction rates called for different options. One of those options was the recently developed CO2 viscoelastic surfactant (VES) fluid system. sed on comprehensive data. This process includes the current service standard of design execution and evaluation but goes far beyond

n a matrix treatment flows into high permeability sections and/ or high water saturation thief zones" resulting in higher water cut due to the o by management. In response the reliability of these tools and their interpretations for determining the existence of poor behind casing ceme or both liquid and gas wells. Approximate solutions for the early-time and late-time pressure behavior are derived from the rigorous solution ensive test program including flowing and static pressure surveys modified isochronal test two buildup tests and FloScan Imager (FSI) lo nsient solutions that use rate-normalized-pressures and superposition-in-time to evaluate response accordingly to the fracture flow periods ng Company (GNPOC) in Sudan has several wells that commingle production from the Aradabia Bentiu-2 and Bentiu-3 formations. These lling problems associated with high mud losses when the well encounters fractures often prevent well penetration of the total formation thic e propagation is not diffusive but it propagates like a wave with a finite speed. If we have a pressure gauge at a distance we will only start the pressure and hence the deterioration in well deliverability can be continuously and cost effectively monitored.� This paper illustrates of all these methods revealing and discussing specific features associated with the use of each method in a unified manner. The algorithm

t analysis is a recommended technique for fracture evaluation but its use is still not well understood. Analysis of pressure transient data pr ed reservoirs is the presence of vertical heterogeneity and varying layer flow properties. Wireline formation testers have been commonly us ngle or multiple flow periods induced using a downhole pump followed by a pressure buildup. The objectives of a MiniDST are sampling es ertainty on oil rates. To solve such metering challenges with a large majority of their wells operating above 95% gas fraction under metering es the challenges and potential benefits of deployment in line multiphase flowmeters in the difficult operating environment of Northern Siber

can lead to unforeseen errors in the field. Recent experience shows that in certain conditions the various types of multiphase flowmeters re by many operation companies worldwide. However in artic environmental conditions like those of Yamburgskoe gas-condensate field with r the measurement of gas flow rates particularly those of wet gas. A new interpretation is described that allows a traditional multiphase flow qualify the multiphase meters results before use and considered parallel testing with conventional separators to allow fair comparison of res

d on past experience or special cases which could be several years old. A split in terms of naming is even commonly accepted in the multip btained by reconciliation of the analytical well test model with the numerical full-field model. We present a more complete approach where a ctured wells. The purpose of this paper is to demonstrate the application of the production data" formulation of the β-derivative function (i.e test interpretation. In contrast measurements from new pressure gauge systems can now provide the stability and resolution required to ch ts but nonetheless record high signal-to-noise ratio responses. These field experiments have demonstrated that the streaming potentials ari

efects in the cement sheath. It is therefore of critical importance to understand and characterize fluids and solids across the caprock. This h leak-off test data a borehole wall electrical image and dipole sonic log data in the CO2 injector CRC-1 are used to constrain principal horiz or to the surface. In this paper a risk-based approach is proposed for well integrity and confinement performance management. The approa ls. A recent trend of the industry is the integration of sub-surface and surface simulators to have a better representation of the fluid producti n in these situations is one of few means of assessing an injection site and testing various scenarios. The accurate description of physics an standing of the processes involved in underground CO2 storage evaluate applicable monitoring techniques and provide operational experie e; Enhanced Oil Recovery (EOR) Enhanced Coal Bed Methane Recovery (ECBM) Enhanced Gas Recovery (EGR) Food processing app to properly manage containment performance and leakage-incurred risks. The analysis starts with the construction and the calibration of a

at 8560 m / 28084 ft measured depth. The well includes three hydraulically operated flow valves which are used as down hole chokes to y is greater than 11.6ppg. This resultant high overbalance and other issues such as hole cleaning complex directional profile ECD manage

have been waterflooded and only five have experienced CO2 injection. An ongoing US Department of Energy project is studying the use o al occurrences of natural CO2 that have been discovered during exploration of oil fields. The CO2 that has been naturally trapped in carbona nated sequences; many thin high-quality sands have been overlooked. These sections can now be discerned using microresistivity measu reservoirs have been producing with vertical wells.�This paper presents a practical strategy of rejuvenating gas-condensate reservoir p s in the process specific to the selected area and to understand the effects on the recovery factor in these reservoirs which have previously wells were required to be treated to shut-off source of the gas breakthrough in order to restore oil production. Challenges faced in shutting of

sure formation and a micro-fine cement system for sealing off the water entries. Based on this study a cost-effective chemical treatment me ff case history of an oil producer that has shown according to the production data an increasing water production figures. The nature of wat ms. As a result most exploration and production companies have learned to manage water production up to a tolerable limit which is depen set in open hole. This paper shows that this type of water shut-off in open hole is feasilble and very effective. This will open the doors to ap meability modifiers to control water production in these completions has traditionally produced inconsistent results. This method can fail to c mentally friendly manner. Some fields in Saudi Arabia use water injection for reservoir pressure maintenance which makes water productio ucer with 2 440 ft of reservoir contact was drilled and completed in November 2000. The last well production profile was determined by a F e near-wellbore regions and production tubulars. Besides hydrocarbon solids other production hindrance elements include wellbore fluid lo tion and droplet size as a function of flow patterns and were used in characterization of the flow and performance evaluation of an oil/wate sing tap water and mineral oil with superficial velocities ranging from 0.025 to 1.75 m/s. The experimental results include observations of flo r a static problem.� They cannot account for the dynamic changes that occur in time in the connected system of reservoirs and wellbore g into account surface facility constraints that could lead to unrealistic approximations. Restrictions in compression power or pump capacity deposits having varying fluid characteristics. To reduce the risk we have adopted a systematic approach to evaluate the potential impact of w assurance aspects of a live waxy crude oil from offshore West Africa is investigated. Experimental work included determination of the wax e safety of equipment and personnel. The conventional procedure to evaluate the CO2 content in a hydrocarbon bearing formation is to tak osition. Examples from two such reservoirs one from the Browse Basin in Australia and the other from the Malay Basin in Malaysia will be d

clines and changes in the specific gravity of the reservoir gas as reservoir pressure declines. No correlations based solely on field data hav oil-gas ratio exists in the petroleum literature. Alternatively oil-gas ratio (needed for material balance and reservoir simulation calculations of d laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients prov mited lateral extent and hard to correlate. Several layers are potential pay zones and may contain oil or gas. However water zones and seco ance in the oil field. Furthermore different depletion/development levels and injection and production processes of different reservoir zones conditions of the downhole environment limit the DFA-tool measurements to only a small subset of the fluid properties provided by a laborat n simplifying assumptions in terms of the compositions of flowing fluid phases. These models characteristically assume single-component p id phases detection saturation pressure as well WBM & OBM filtrate differentiation and pH which is key for real time contamination monito

nd sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Reso an economically make or break a project. Traditionally operators have relied on well tests to determine H2S levels. In addition to the expens

rements. Our analyses of many samples show that a good correspondence exists between the PVT-derived gradient and that obtained fro e provided valuable insights into compositional grading but each analytical method relies on different fluid traits and has different implication d in the zones of interest is extremely challenging especially when it is associated with overpressured low porosity shaly sandstone reservo s uniform and free of noticeable impermeable layers. A resistivity log showed an approximate oil/water contact (OWC). Wireline pressure tes ation of in-situ fluid type can be difficult. There is also mounting evidence for the presence of compositional gradients in the hydrocarbon co density fluid contacts and layer connectivity in exploration settings. This information is today supplemented by downhole fluid analysis (DFA sure/volume/temperature (PVT) properties. A technique of monitoring sample contamination from OBM filtrate uses optical means to monito

eservoirs which are not in equilibrium but still undergoing for instance a flux of the light components that diffuse. Formation testers supply m measurement and the oil-based mud (OBM) filtrate have been taken into account. Recently an algorithm called the fluid-comparison algo nditions of the downhole environment limit the DFA tools to measuring just a small subset of the fluid properties provided by a laboratory. Ne

ems the paper gives full details for a 3-phase oil/gas/water system.� Any number of hydrocarbon components may be present and water nder the actual production conditions is necessary. This study is an attempt to investigate the effect of water content pressure and tempe

es and requires analytical methods to back-calculate the measured properties to approximate the uncontaminated reservoir fluid. The ability ate sampling has always been the trickiest because even little traces of contamination may render the sample useless. Besides that the too pted for several years now by the industry. Their use in permanent or well testing applications has been growing rapidly. In many cases mu ant benefits to the ease of deployment especially in harsh regions such as the one encountered in Northern Siberia. One of the past challe s stimulation fluids. The advantage for chelating agents is they can complex with calcite and form water-soluble products. Different mathem on damage make any stimulation a challenging and detailed process. Water injection is one the most commonly used exploitation method actions carried out under controlled conditions as well as within the pore space of sandstone cores. In the controlled reactions solutions of c mmercial halite inhibitors are only effective at high concentrations (250 – 5 000 ppm). Therefore a more efficient salt inhibitor would need

. Core-flow tests were conducted to generate naphthenate-soap particles and to determine the permeability impairment caused by subsequ atrix by de-bonding the cohesive inter-granular cementation leading to the creation of a zone of reduced strength called the damage zone. age and maximizing productivity though the mechanism by which it does so is still not very well understood. Underbalance perforating also scale precipitation prevention no successful attempt to enhance scale prevention in conjunction with a stimulation treatment has been docu antly to be effective in the typical Uinta Basin gas well environment: low permeability (90 %) deposits in many sedimentary basins. Several CO2 fields in the United States Hun standard logging run the analyst will view the density porosity output and question the economics. “What is the porosity cutoff to mak done to evaluate the effect of fluid type reservoir permeability lateral length and reentry drilling time on production performance.�Resu il contained in these accumulations and their in situ viscosities natural production mechanisms will render low recoveries. Therefore suitab red. Because GOGD is not effective in sparsely fractured reservoir water flooding those layers was expected to substantially increase recov

ese micro-pore types can be only beneficial for reservoir if they had linked together by fractures and microfractures which were formed due ng the water shut-off treatment. An oil producer that has shown -according to the recent production data - an increasing water production fig ssible because the perforations are behind the production tubing. For such single-string selective completions only a pressure test can be p

eld has had over 800 wells drilled with 525 of them currently active. Most of the shut-in wells in the field are located in the south end of the ated in order to determine if CT can get to the target depth without locking-up and that the maximum tensile and compressive loads require

f Health and Safety Executive (HSE) management to execute and involve potentially lengthy downtime. Being able to predict the presence ogether they are characterized by the existence of diverse flow configurations and flow patterns or a geometrical arrangement of the phase se flow provided that the dispersion effective viscosity is properly estimated. There is limited information on the intermediate flow patterns w n restrain the inflow from the completion into the production tubing by choking the fluid flow from between fully open to completely closed. the decisions have a limited influence on the overall performance of the system. In recent years operating oil and gas companies have sta nsify the asphaltene precipitation condition. Results also indicate that wax precipitation will not be an issue during the life of the project. Int ax components of the crude oil are not properly characterized. Critical properties and interaction between these heavy wax components are cted early in any exploration or appraisal campaign. Corrosion is more pervasive in the oil and gas industry than commonly perceived. It att and near-infrared absorption spectrometer for fluid discrimination and a refractometer for free gas detection. Since then other generations o

n the prediction of ultimate recoveries of condensate. A surface-yield correlation has been developed that is a function of a selected reservo atment of the liquid in the gas phase. The MBO approach assumes that stock-tank liquid component can exist in both liquid and gas phases ufficient data. The new technology of Downhole Fluid Analysis (DFA) has proven very useful for the early identification of fluid gradients [9 1 ons of changing fluid characteristics. For certain fluids pressure decline causes thermodynamic changes (such as solids precipitation or sig nce between predicted and actual performance in the oil field [3]. In many matured fields the No. 1 problem is “where injections fluids s

ent between our model and common field observation motivates use of our model to analyze the more complex WFT probes which have re he details of NIR application for DFA have been described elsewhere [2 3].

ed. Evaluation of saturations/remaining oil determinations becomes quite important for the determination of sweep efficiency in mature reser in general. The need for accurate determination of H2S concentration in the reservoir fluids to be produced is crucial. It may mean higher p

ture gradient in a reservoir (Pedersen and Lindeloff 2003; Hoier and Whitson 2001; Ghorayeb and Firoozabadi 2000a and 2000b; Firoozab han the existing hydrocarbon column filling will occur at the oil/water contact and may not readily mix with the rest of the column. The range ossover together with high value of resistivity suggests that the formation is gas bearing. Normally formation pressure gradients obtained fr nt to determine the magnitude of these gradients by actual measurements. Current wireline formation evaluation is inadequate to determine These new applications could include improved integration of pressure measurements and pressure gradient analysis with reservoir fluid a to reveal non homogeneous fluid distributions in reservoirs [1] [2]. Light and near critical reservoir fluids often exhibit significant continuou R prediction results for dark oils. Introduction Real-time estimation of sample contamination by drilling-mud filtrate is critical for the collectio

actual measurements. The reservoir architecture is revealed. For both cases the fluid column is continuous through the hydrocarbon interva s measured to estimate fluid composition and GOR (Dong et al. 2003). Second hydrocarbon spectra show a continuously increasing absor ontamination monitoring composition measurement and single-phase assurance can provide real-time fluid property information during fo

will also boil and at first three phases are formed.� Add more heat yet and one liquid phase will disappear.� If the oil is light such as a ncreases. With enough shear force (e.g. flow through a downhole pump or a flow restriction such as a choke valve or orifice) a stable emu

o understand fluid behavior during the production and life of the asset. Reservoir engineering and production strategies are crucially depend chambers in the string which served the dual purpose of increasing the length of the flowline and taking additional big volume fluid samples n proposed from Heavy Oil to Condensate (Ref. [2] [3] [28]). The way to handle this need is very simple and until now only two approaches The paper focuses on the sampling and fluid analysis aspects and utilization of the fluid information for multiphase well testing. The consist sed acids are very corrosive to well tubulars. One way to address these issues is to use organic acids. The two main organic acids that are arameters are disrupted with the evolution of damage in the near wellbore. To diminish this detrimental effect two actions are necessary. Fir ed for carbonate stimulation is largely only varied to a slight extent in order to find the optimum conditions (rate of dissolution) to generate w ion is generally easier to remove than other type of scales by washing with fresh or low-salinity water periodically frequent treatments nece

e permeability of a cylindrical rock core sample is determined both axially and radially before the perforation experiment as well axially thro ked debris of high permeability (1–10 Darcies).�Immediately surrounding the perforation tunnel is a “damaged zone of fractured ro ½ï¿½ï¿½ï¿½ï¿½Changes in temperature pressure or pH; ��������3. ��������Mixing of incom ring job. In a properly executed treatment the scale inhibitor should: cover the entire length of the propped fracture (as opposed to a sque ability to deliver flow assurance. e related problems such as interference with producing wells wireline operation and minor production losses. With more than 400 producers lfield in the North Sea[1]. Gyda receives limited aquifer support and is developed by waterflood.�There are 32 well slots of which curren nable match is first obtained at the field level then at the regional level followed by more rigorous individual well history matching. In this p match and prediction under waterflooding system. hing exercisesl. The essential or main benefit of streamline simulation is the often very dramatic improvement in simulation turn-around time g complex sectors that incorporate radial local grid refinements. �The findings have been encouraging in terms of extra oil recovery by th dantly described in the last five years.� Most of them involve high frequency data streams provided by smart completions that involve larg electromagnetic surveys. The main objectives of the WI pilot project are: 1) determine sweep efficiency in the target reservoir units 2) quali n 7 100-8 300 ft. drilling depth and include various high-productivity Burgan sandstones overlain by a more moderate-permeability shallow-w 30�F. To exploit these extensive extra-heavy oil reserves economically new drilling and production technology implementations have be ogy to produce heavy and extra-heavy oil is still under accelerated development to meet the challenges to efficiently produce and procure th 1992; 1995). These materials are in general poor receptors of microwave energy so they cannot be heated directly up to the high tempera ence to optimize the performance of the HASD process for sand bodies of medium thickness. ter production and control the sand incursion problem. Geological Setting The development of oil-bearing basins in Sudan is closely associ ergy inner shelf or ramp setting in a gently dipping restricted ramp environment. The presence of minor interbedded evaporites suggests re e permeability anisotropy in spite of difficult and challenging acquisition (operations were done from Geophisika Logging unit due to the fiel

r important driving force behind drilling horizontal wells is to improve the light oil production from Aradeiba reservoir that is crucial for blendin

d. The primary challenge to commercially produce Issran field heavy oil is its mobility. The mobility and resulting productivity are mainly rela

raditionally hydrofluoric (HF) acid-based systems have been used to dissolve aluminosilicates in sandstone formations. These formulations and field development planning. Furthermore comparison between core permeability formation testing fluid mobilities and NMR permeabi

y variations (such as the existence of salt structures) or changes in the overburden thickness may create the temperature differential neede

neously just after the fluid exits the perforations avoiding high friction pressure and degradation resulting from shear in the tubulars and per n. In such treatments the injected acid is consumed by either reacting with the fracture walls or leaking off through the walls of the fracture t

eld are found in 3 main reservoirs: Miocene which is at depths up to 10 000 ft TVD Oligocene which is at depths up to 14 100 ft TVD Na solvents are being used to treat these wells with mixed results. The new sandstone acidizing system is developed to effectively treat mult me treatment fluids. For comparison sandstone reservoirs undergo matrix acidizing treatments to remove damaging aluminosilicate miner rvoirs in the San Jorge Gulf Basin. To make matters worse the low well productivity offers operators only a marginal return on their investm does not pose a problem.[4 10] The slow clean up of water blocks by evaporation can be enhanced by addition of volatile solvents. Succ l development strategy to prevent scale formation by choice of operating conditions to select and deploy scale inhibitors when needed or b

mpletions in the past four to five years (Figure 2).(1)

to change our focus now to how to develop the available gas reserves. Globalization of gas supply and demand has launched tight gas as irectional drilling from pad wells to reduce surface damage. ar Rosneft-Yuganskneftegas use hydraulic fracturing almost without exemption in all new wells as a conventional completion method. Additio 10 11 12 There are indications of microseismic activity being related not just to stress effects but also to actual fluid movement 13 14 and

te Noire. Average water depth is around 100 meters. The field was discovered in 1998 by the well FOKM-1. Production started on June 200 ich is the very first in East Asia is considered to be a major breakthrough in China for PetroChina in particular because the technology has opment has historically focused on the relatively more permeable 20 to 80 md thin-layered Ratawi Limestone interval with minimal conside D geocellular model which captures the properties and heterogeneities of the reservoir that is subsequently upscaled into a dynamic simula l economics.� Introduction ��� The majority of the Uinta Basin is located in northeastern Utah with a small portion in northwest eservoirs consist of several sand units over a gross thickness of 4 000 ft in a fluvial depositional environment. The thickness of individual sa dard and higher anticipated natural gas prices. These are the pay sands that are still only partially exploited and bypassed on an ongoing ba

e important for providing the needed permeability allowing the well to flow. formation testing technologies including new techniques applications and tool reliabilities over the past few years has caused a significant discovered in 1956. With an original oil in place (OOIP) estimated at 41 billion barrels and a total production to date of 5.4 billion barrels or rvoir presence and quality and ultimately dictate well performance and optimal well density. Figure 1: South Central Wyoming Regional Ge

. ����The rubber packer makes a seal against the borehole wall isolating the center probe area from the mud column therefore a for proper well placement. Consequently a multidisciplinary geological and reservoir modeling team helped to define the optimum waterflo

ncepts of 1970es. As a result of the exploration effort taken in 1980-es the structural model of the pre-Vendian units of the YTZ was develo

wept or if there is movement of the OW contact. In addition some authors [2-7] have explained the importance of changing wettability; the t

stantial manner. General technological development in all walks of life resulting in continuous increase in oil demand rise in oil prices and g

chniques by each individual in determining the specific decision of choice. In many cases these techniques or heuristics lead to high quali iases are related to how our socialization affects our judgment. It is impossible to find anyone who manages an oil and gas exploration and

ermeability) vary significantly horizontally vertically and with scale. Understanding these issues is critical to successful reservoir manageme recovery. This is particularly true in carbonates for which reservoir heterogeneity exists at many different scales. Detailed reservoir charact Newberry2 introduced a technique called PoroSpect* that allows porosity mapping of the borehole. Primary (e.g. interparticular porosity) an sin is northeast-southwest. The basin contains thick sequences of sediments with several cycles of deposition ranging in age from Late Car m different sources can help reduce the geological uncertainties." for reservoir evaluation and management. Reservoir-fluid properties such as hydrocarbon composition GOR CO2 content pH density vis n are some of the reasons of changing fluid characteristics. For certain fluids pressure decline causes thermodynamic changes (such as s eability of the carbonate system. To understand the permeability of the reservoir a pore classification method may have to be resorted which odeled geo-statistically to define the spatial heterogeneity and to visualize the distinct compartments within the reservoir. Using single well p ing and allow for a caliper measurement even when sliding. Finally an azimuthal gamma ray measurement device capable of producing 1 not having to use a chemical logging source. Introduction and Geological Setting Understanding the porosity distribution and type within

or the shaly sand formations as it assumed that the only conductive phase in the formation is the interstitial water and considered the rock rmations as it assumed that the only conductive phase in the formation is the interstitial water and considered the rock as insulator. In the p have presented a rock typing scheme based on property cut-offs thin section analysis and high pressure capillary pressure data and poreal and the depositional framework. In the present study logged intervals of studied well present a medium dipping sequence with dip azimut re based Dunham classification and high resolution sequence stratigraphy.� The high resolution sequence stratigraphy which recognize and and shale layers.� These beds are often too thin to be properly resolved with conventional logging tools. The acquisition of new tech

ivity anisotropy in thin sand/shale formations (Cao Minh et al. 2007).2 Both papers contained many useful references that will not be re-quo

many authors. These topics are particularly well documented by Rahmouni et al (2002) and Guehria et al (2005). Similar patterns in produ tion testing and sampling jobs or require multiple trips into the well to acquire the required samples and fluid profiling stations. Mitigating the ress directions through the analyses of breakouts and drilling induced fractures. For example the Fullbore Formation MicroImager (FMI*) p west of the Al-Khafji area onshore in the SUG and Wafra main fields. 3D seismic survey was acquired in the Al-Khafji where a number of w

he nineteenth century while frequency statistics played a more dominant role in the scientific applications in the twentieth century (Efron 200 out flow potential. The petrophysics and borehole geology analyses therefore had to be completed in near real-time before the wireline form rived hydrocarbon volume was then compared with the results estimated from a full triaxial (3D) induction tool. Permeability of the sand laye

on this past work we know that in the case of uniform depletion in the reservoir i.e. when pressure gradients in the reservoir are small stre

yielding increases the shear slowness stiffening would reduce the shear slowness. Introduction Formation stresses play an important role

rate inner boundary condition. (2) The definitions of the dimensionless variables used in this superposition relationship are given in terms

racture was expected to contribute better reservoir quality over especially the carbonate reservoir rocks of Thebes and Mokattam Formation ovskoe Urmanskoe Gerasimovskoe and others). In all of these fields oil was produced from the basement carbonates and weathering crus with seismic faults present in the field. A total of 8 major and 51 minor faults were observed with a dominant NW-SE strike direction consi others). In all of these fields oil was produced from the basement carbonates and weathering crust. Further investigation on Pre-Jurassic re

tive permeability effects – most pronounced in tight water-wet gas sands where oil based mud filtrate is the third phase introduced into a

s; quartzitic sandstones litharenites micaceous and laminated sandstones together with shaly intervals that can be found in the productive r saturation Sw prior to WFT operations. Castelijns et al. (1999) show the use of NMR continuous permeability k to select test points at the

ue data quality and time. One of us (RA) addressed some of these issues by introducing the idea of “everyday NMR in a recent paper ( measurements like those used in modern laboratory-NMR instruments. The value of these measurements is that they are extremely flexible

having high compressional stress. Failures have been reported while tractoring in open holes with soft formations.

ing injected and produced fluids. This of course would assume that in-situ downhole conditions such as temperature and flowing wellbore ved defining three structural periods: EW and NS faults crossing the field in its central part during the Hith-Shuaiba period; mainly EW fault

riers evaluation of connectivity across faults and prediction of fluid contacts. Downhole Fluid Analysis In recent years formation sampling ever a detailed analysis of the fluid in the rock is not possible today. The closest alternative is the acquisition of downhole fluid samples acco nner boundary condition. Equation (2) The definitions of the dimensionless variables used in this superposition relationship are given in ter t divides the field into eastern and western zones each with distinct saturation pressures. Observed only in the western part of the field are nation therefore fluid analysis using wireline formation testers is a very important step during the open hole evaluation stage. As noted thes

in a reservoir exploited with wells stimulated with long hydraulic fractures. Various techniques exist to determine stress direction and magn eed a complex initialization process and would require data that is not readily available. The ensuing interpretation would be overtly complex ti-discipline multi-scale data and utilizing 3-D numerical models as predictive tools. Then estimating risk from the remaining uncertainty allo g fluids in place fluid contacts and extension of flow units. In other cases the reservoir architecture is more complex and pressure data †technology to Bokor Field and prove its value for entire Baram Delta Ensure the knowledge transfer on ESP technology and techniques to ESA) is located in the Talara basin in the northwestern coastal region of Peru (Fig.1) and has an area of 470 sq. Km all onshore. Oil and a.� It was discovered in 1970. The field is operated by Petronas Carigali Sdn Bhd. The first phase of development began in 1982/83. The

ch have produced over 400 million bbl of oil and 1.1 Tcf of gas. Six major fields account for 90% of the production from 12 zones ranging in d reservoir management strategy Optimum well type (vertical horizontal multilateral) and completion requirements Fig. 1 illustrates the na d re-circulating (in the case of gas) of large amounts of the secondary phases to continue with the previous oil production rates. Figure 1 sh potential field from Maracaibo Basin. Moporo field has a cumulative production at 320 MMSTB under natural depletion with reservoir tempe amework provides a new horizon of powerful tools enabling the emerging smart field workflows. This paper presents a comprehensive set mples include well workovers zonal isolation artificial lift installations upgrades of field equipment and remedial operations to mitigate flow anomalies and to identify areas where recovery could be improved. This is particularly important since at the present time no infrastructur ch 9 development wells were drilled. Two other structures house the separation facilities and a flare boom. Three “Revisit campaigns we

he fluid rates or the pressure at the surface coupling point (e.g. well head) where the well model is linked to the surface facility model. The Oil & Gas company inductions and they will use the technology to solve many pains from production optimization operations surveillance the decisions have a limited influence on the overall performance of the system. In recent years operating oil and gas companies have sta gical and engineering modeling.� By definition this is an iterative process until all the disciplines agree to a model that is acceptable with meability measured in the Darcy plus range. Aquifer support is strong helping to sweep hydrocarbons but also causing rapid water breakthro

ration were defined by performing lot of screening using gas lift allocation models. ate oil production these fields have gradually entered into a mature and high-water-cut phase. Oil to water contacts (OWCs) have significan in an area of known depletion; the highest-rate Miqrat production well an overall improvement of zone productivity and a better understa ntroduction The Lower Vicksburg sands in the study area are heterogeneous low permeability and geo-pressured. Economics dictate the earning). In this paper we develop a mathematically consistent framework using decision trees conditional probabilities and Monte Carlo s

shallow (several inches only). Traditional electromagnetic propagation tools (2MHz) are sensitive to electrical anisotropy and bed boundarie In 2002 Oilexco North Sea Limited was awarded licenses to develop blocks 15/25b and 15/25c within the Outer Moray Firth Basin. Betwee hodology of sequential well placement across the entire reservoir therefore complements and completes this prior work.� Introduction T for the elimination of fines leaving a blocky unconsolidated sandstone as the reservoir. Between thicker sand-dominated depositional eve the application of new technology into the field at low cost when� significant reserves are accessed.� However the critical aspect is i oil production in an aging oil rim field. Extensive reservoir simulation on a full field model was utilized for the initial well placement study. In p econd category can in theory avoid this problem but has the disadvantages of not increasing NPV at each iteration and requiring many for

e to laminar flow of fluids in a porous medium were the results of Darcy’s experimental study of the flow characteristics of sand filters. can be extremely useful they are based on very simplistic physics and fail to fully account for transient effects and interference between we an inverse problem. Such inverse problems are usually ill-posed and their solutions suffer from difficulties in existence uniqueness and sta own as “History Matching which is considered the most time consuming phase in building a reliable model for the field. Thus any reduc

atched model must not only reproduce production data by numerical simulation but it must also be consistent with the geology in true sense

resents comparison of simulation results against other simulators to verify the physical results. Mathematical Formulation The thermal mod ation and mole fraction formulation (IMPES) and implicit pressure and saturation and explicit mole fraction formulation (IMPSAT). Furtherm in large areas from a limited number of platforms. However due to a variety of reasons the entire completed interval may not contribute to

cost efficient manner. This is especially true for offshore fields where these wells are used to drain large areas with limited platform capacit

nues to leak off into the reservoir. Alternatively and especially for tight gas reservoirs the fracture can be forced to close by flowing back so pairment in tight-gas reservoirs. Many tight-gas wells do not respond to hydraulic fracturing as expected. Following the fracturing treatment 5 exhibit better rock quality than 2 and 3 but they still benefit from stimulation. The bottom zones - 6 and 7 - similar to zone 2 and 3 in bein sis of so called “black oil technique.�� So the multicomponent multiphase fluid model is necessary to predict the performance of h heoretically. It is well known now that in-situ stress contrast is the dominant mechanism that affects fracture height growth. It has also been that adequately represents both the large range of influential reservoir parameters and their inherent uncertainty. The most common way

esents a concise and clear discussion of the deficiencies and limitations of the allocation method. The non-linear regression method2 propo n terms of the pressure drawdown between the average reservoir pressure and the sandface flowing pressure ) and the classic transient te ure geometry. Over the past twenty years however it became even more obvious that none of the available fracturing models were matchin es and Nolte 2000). You may ask how to achieve this ideal perforation. To answer this question or at least provide some recommendations NNs are widely used in prediction and classification problems and have numerous applications in geosciences and petroleum engineering i

the fields in the Delta of Egypt. It is located to the North of Cairo and it is about 64.6 Km2. Figs. 1a and b show the location of South El-M e estimated with “production logging technology but this may require coiled tubing to access the full length of the well. Even with coiled

an important issue in material balance calculations. Uncertainty due to data errors can be found in field production data measured PVT pr

rm composition. Natural convection also can result in increased horizontal compositional variation an effect similar to that in a thermogravi bove typical steps in an experimental design workflow. The paper presents the lessons and experiences distilled from the application of ED a

missibility upscaling method (TU-method). In contrast to upscaling of permeability which is associated with a single control volume (e.g. see

the fracture system or be isolated in matrix material which constitutes a triple porosity system.� Several publications2 3 have addressed pproaches depending on the origin and the type of fracture sets and on the ultimate reservoir engineering questions raised. In this paper w

mplicated geological multiwell models that require a large number of grid cells and therefore require either very large (parallel) computing ef or and much better scaling with respect to the number of grid cells and heterogeneity for three-phase compressible dual porosity simulation on and displacement processes. Fractured reservoirs are complex geological structures in which fluids are stored in matrix blocks and flow

cation of uncertainty obtained with RML with the one obtained with the ensemble Kalman filter (EnKF). The PUNQ-S3 reservoir represents

ecipitate inorganic scale – thus making the brines incompatible (Yuan and Todd 1991). For example if sea water which is rich in sulphate

the pressure equation should be solved; between the pressure updates saturations are transported using a frozen velocity field. As the na h specific procedure uses cubic equation of state like for example Peng-Robinson for determining thermodynamic characteristics and equ p methodologies which are strong enough to tackle the aforementioned technical challenges transforming these opportunities in real bottom

bjective function based on the full pressure data only the dominating patterns in the simulated pressure data with the recorded pressure d 06). A former restriction of the multisegment well model was that it could not represent looped flowpaths within a well. Thus while flow in an

le oil) with average temperature pressure and saturation pressure of 275 oF 11000 psia and 5500 psia respectively. Reservoirs flow prop

������������������������������������ WL (location where there is zero capillary pressure between oil and water) OWC (as depth increases below the oil zone the location at wh ced drilling (UBD) campaign was initiated from a mother wellbore to drill multilaterals. The drilling plan was to be conducted through the pro fields those are now being developed; the original data quality is very poor or inadequate to extract meaningful results that could be used t re several operators notably BP Chevron Norsk Hydro Saudi Aramco Shell and Statoil have flagship fields where many but probably n

North Slope (ANS) petroleum province is defined as the private municipal State of Alaska and United States federal lands and waters no ns in the cement sheath was also discussed by Bosma et al. (1999) but this will not be addressed in this paper. Both types of models ass

bridge plug. The same rig was used for the logging and the setting of the bridge plug. The water shutoff operations successfully increased ulic flow control valves. Norsk Hydro then turned its attention to flow control of multilateral wells. A completion solution integrating flow contr on history of more than 40 years. The depletion drive mechanism causes the swift pressure decline in the field. Studies indicated that water his left two possibilities: coiled tubing conveyance with a hydraulically powered tractor or wireline logging with a new much more powerful tra

commendations that were made and their implementation. This discussion is informed by the fact that these are low permeability rocks drill

enhance reservoir modeling efforts. r which can be difficult and costly to obtain. The quality of formation-water data is highly dependent on the sampling technique and the type oir properties that will be analyzed not only by absolute value but also by trends frequency and impact on other dependant variables to al geological history and low permeability of the Canyon sandstones in this region (Marin et al. 1993) the hydraulic fracture stimulations are c ove the production (eliminate skin) of its existing moderate permeability reservoirs (ranging from 5.0 - 200mD) and unlock its large reserve b

h they are pumped to the surface. Total E&P Canada installed a pilot horizontal injector/producer pair in their Joslyn field in 2004 as Phase e wellbore to the surface.� Turner et al3 identified that there are two transport mechanisms that must be considered in evaluating the tran e. Turner et al3 identified that there are two transport mechanisms that must be considered in evaluating the transport capability of a system ation has been the length of time for a well to stabilize thermally often exceeds the production log duration causing incorrect temperature lo

tall a meter on each well thus preventing continuous flow-rate and cut measurements on each well. This introduces the same type of uncer

owever production can also be limited either by reservoir constraints or process constraints that also need to be included in the Production ity measuring gradiomanometers and full bore spinners are inadequate for characterizing separate phases in stratified flow. One approach d communication between the Wara and Burgan sands has to occur through partially-sealing faults with throws considerably larger than the Generally asphaltenes tend to remain in solution or in colloidal suspension under reservoir temperature and pressure conditions.� They of the intervention of modern technologies in overtaking the challenge. Here we are going to focus on one the wells in the field of scope and WFT evaluation program is unique. Some may include only a pressure-gradient survey for reservoir depletion and communication informat n during the shut-in. Alternatively one can perform a multirate IPR test using a production logging tool (PLT) log which again results in loss o tiltmeters respectively could allow the steam injection to be tracked with complementary technologies that respond to different expressions sandstones with excellent intrafield connectivity and permeability interbedded with shaly layers. The reservoirs are part of a multilayered sa s to be installed in the period 2008–2012 representing over 60% growth from the period 2003–2007 when 1 467 wells were installed. A

side of the process from the sales or delivery point to the wellhead. It is also necessary to evaluate the other side of the process from wel r shut-off program with the objective of restoring oil inflow. Difficulties in acquiring quality data in horizontal flow environments specifically w

onitoring and future actions for enhanced recovery. Introduction The different techniques of reservoir monitoring and maintenance enhanc

ast to be easily picked up by the technique and 3) the flood front progress can be captured by conducting the surveys in a time-lapse mode bypassed oil and residual oil saturation are secondary considerations of the WI pilot study. Production injection saturation and pressure d er Basin has 12 000 wells in production and an estimated 50 000 more wells will be drilled in the next 5-10 years. Wells in this basin are now called cleats. The extended continuous fractures are termed as face cleats and subsidiary shorter length fractures are classified as butt cl hat requires exposure to a much lower pressure in order to desorb and produce the gas but also coal seams are highly susceptible to near nd is abnormally pressured in this area. Commercial production is achieved only with hydraulic-fracture treatments. Before 1997 Barnett s cture initiation occurs the treating pressures can remain high inhibiting the normal progress of the treatment (e.g. low pumping rates are in

ly 1 Bcf in Denton and Wise Counties economics were marginal due to high completion costs and low commodity prices.� By 1996 the w ture characterization and production evaluation can be found in Louks et al. (2007) Gale et al. (2007) and Frantz et al. (2005). In order to s. The combination of these factors in reservoir studies limits the results that can be obtained. Our study examined several completion strat . In shale-gas reservoirs gas is sometimes produced through more-permeable sand or silt layers interbedded with the shale through natura ure diversion technique is ideally suited for re-fracture stimulations it is also applicable for stimulation of new wells where the technique en d by the acid injection rate. The materials dissolved by acids are typically the pore lining or filling materials rather than the matrix framework

ed across it. This causes further rise. The process continues until the fluid column reaches the surface. Meanwhile the high pressure and a ld comprising 26 stacked pays which belong to Cretaceous and Jurassic systems (groups of PK AS BS and JS reservoirs). It contains mor

stimulations vs. potential well production. One of the most important parameters affecting production is the number of layers fractured durin perforating method to pass the radial extent of near - well bore mechanical alteration. After perforation the production test showed a 3-fold methodology discussed in this paper as well as the production optimization model in general is not necessarily restricted to use for vertica methodology discussed in this paper as well as the production optimization model in general is not necessarily restricted to use for vertica rence 1 contains more details about production performance of these 16 wells.� Thus the objective of this project was to drill a tri-lateral

e left with high oil saturation. This may also be termed as poor “load balancing. The literature on the concept of locating missed pockets ontrolled variable multipositional hydraulic system. This paper discusses a closed-loop approach that led to efficient realtime production op

orresponding laboratory tests. One of the biggest disadvantages of using acid in the well is the aggressiveness of these fluids making it imp nalysis approaches to ESP performance analysis. Background on SA is then provided along with an outline of the three main classes of S

increasing diesel fuel costs led the team to consider reviewing alternative fracture fluid systems to determine the impact on well performan

e generated oil. Fig. 2 shows the productive Bakken Middle Member in the Richland County Elm Coulee Field. The “Bar Trend is a very were the prime target application for this novel technology where low concentration and small mesh size proppant fracture treatments are ty

n issues and to prevent proppant flowback in hydraulic fracture stimulation1. Most recently however the scope of fiber application has vast pillary pressure of the fluid in the near fracture region should improve flowback of the fracturing fluid and reduce the drawdown to produce. h the development of tiltmeter and microseismic mapping services more direct measurements or estimates of hydraulic fracture geometry a cost-control measures include reducing additives in fracture fluids and minimizing disposal costs of produced waters by recycling and using costs for their produced water exceeded $400 MM/yr (Khatib and Verbeek 2002). Finding alternative uses for flowback water in the E&P in al completions (single stage single sand) limited entry techniques and Pin-point Stimulation* techniques were introduced to further unders production of formation sand. Ball sealers were used in long perforated intervals as diversion mechanism to achieve better zone coverage. gularly pumped fracture height growth is additionally considered to be a major cause of premature screen outs. The fracture height growth appointing production figures with higher than expected production of unwanted fluid and completion costs. Since the oil could not be recov moval and sand consolidation to maintain an economic production rate. The reservoirs are made up by several stacked reservoir that initi gh a hydrocarbon reservoir. Drilling technology has evolved to a point where horizontal wells can be constructed at comparable costs to ver

m this successful experience are discussed as a way to further enhance the benefits from the technology in future applications.

als at the same time can result in less than an optimal treatment of the reservoir. The treating fluid downhole will be diverted into each laye start either earlier or later than expected. In the first case the fracture length will be less than planned. This leads to early packoff before the onally a new encapsulated breaker has been developed for the zwitterionic VES described here.�The encapsulated material uses a po

NM over time has resulted in a complex vertical sequence of sandstone reservoir.� It is not uncommon4 to see several vertically discrete

ain the formation pressure much higher than the asphaltene onset pressure to prevent asphaltene deposition within the reservoir in addition ation indicated clearly that yield stress can result in only a fraction of the fracture length contributing to production for a long period of time. H The depositional environment was relatively shallow water regions that left sediments forming barrier bars and lagoonal muds.� Storm c

erforations is directly projected into error of the absolute fracture position. We show that the effects on the absolute fracture azimuth may be

ce asperities and conductivity will be high. As the closure stress is increased surface features along the fracture faces may be crushed and on will be used to optimize fracture design pressure maintenance strategy and pattern orientation. Fields and Reservoir Description The P was based on the “cooling effect that was created when the fracturing fluid was injected into the formation interval. Although this analysi

se were the only data available in any significant quantity and therefore a thorough analysis of the available testing practices was necessa of free liquid rate to gas rate. These are in addition to the other factors that determine proppant conductivity in single-phase flow:stress on

hydrite shale or non-permeable intervals. This heterogeneity of the K formation makes it an excellent candidate for acid fracturing treatmen

owicz and Kijko 1994). Most hydraulic-fracture microseismic images are recorded with sensors in a single observation well such that the se

uced stress change diminishes and the minimum stress at the fracture tip reverts back to the original direction causing the fracture to turn to s is the so-called hydraulically driven fracture. By nowadays evaluations of hydraulic fractures propagation and growth were based on eithe management tool. It was only recently that the fracturing treatment size increased from an initial 10-20 tons to 150-300 tons1. The proppant

early JIP effort that focused on the process of polymer concentration and its impact on the fracture clean-up behavior. Special effort was un ected to achieve a plateau production rate of 120 000 barrels per day. Kikeh is produced via a Spar and a subsea production system back to PETROBRAS started a strategic IOR project (named PRAVAP) where strategies like increasing water injection rates improvement in the sel d experiments. In addition the entire fracture is more easily exposed for detailed examination. Early lab studies10 11 were concerned with as and water coning (Betancourt et al. 2002). An estimated 60 auto gas lift systems have been installed at the time of writing of this paper were performed in high rate gas wells four in Amherstia four in Flamboyant and two in Immortelle fields. C&P-1 Well: This well was comp ve enabled an accelerated growth in horizontal drilling. Current drilling technologies have pioneered these advancements to such an extent e enabled an accelerated growth in horizontal drilling. Current drilling technologies have pioneered these advancements to such an extent t Tambora field produces from a series of interbedded deltaic sandstones shales coals and locally limestones. These formations are classif endent and exhibits spatial variability. In south Shaybah where SHYB-220 is located typical permeabilities range from 5 to 10 mD. Three-D s the flow across the entire horizontal section; delays early water breakthrough and uniform areal drainage. It is concluded that Inflow Contro

ated with the reservoir description. Inflow control to a well can be “passive or “active (Jansen et al. 2002; Kharghoria 2002). Passive our understanding of fracture height growth and containment mechanisms the experiment attempted to recreate fracture propagation obse

ogy logging services such as tri-axial resistivity high resolution oil-base borehole images and nuclear magnetic resonance (NMR) logs hav operties depletion water-cut etc. If the strength of reservoir rock is low it will require sand control. On the other hand high strength rock is ive fluid injection are controlled not only by the chemistry and the fluid velocity but more so by the heterogeneity of the rock.� In a carbon m Field-α. In this area the Tadrart formation underlies directly below the hercynian unconformity (Fig. 2) which confirms the progressive ero D which was higher than the expected gain of 35 MMSCF/day (Figure 1). Currently the well is the highest producing well in Resak field with reaches the undamaged reservoir. This process is fundamental to the productivity of the well; however its importance is often overlooked otential productivity per well. Well productivity can be further optimized by applying drilling and completion practices to minimize skin effect f ther a dominant single or bi-wing) and generate a ����fracture with minimum tortuosity (turning from the initiated fracture into the ses after perforating with this method the wells were not able to flow into the production line with a back pressure of more than 1000 psig un operties are very important to estimate hydrocarbon reserve to quantify productivity of a well and to assess the quality of the completion. P . Standard CT in which a pressure activated firing mechanism will be used as part of the toolstring Although these conventional methods lopment. A validated analytical model for predicting perforating gun swell can certainly enhance the effectiveness of both job risk managem

event this crushed zone from being created or to remove it before the well is put on production (or injection as the case may be). onsideration in any completion program.

ack (CHGP) and the oil production pumped to a neighboring platform. This EWT required the deployment of the world's first Electric Subm

with a new ESP with bypass assembly ran on 3-1/2" EUE x 4-1/2" VAM tubing."

e Gravel Packing method has been accepted as a proven standard of completion in the oil and gas industry.1� Sand control measures in r some poorly sorted sands with higher fines content which result in the Uniformity Coefficient (D40/D90) ranging from 2 to 16 and the fines

presence of shale however the Openhole expandable screen with annular barriers is the only completion option except in fine sand envir e pipe and the wash pipe through which the carrier fluid must travel and reach to the entry point into the wash pipe for returns to surface. S

cost. Introduction A significant portion of openhole completions in Nigeria are drilled with a synthetic/oil-based drilling fluid (S/OB) due to ductivity and/or excessive maintenence to both downhole and surface equipment. Extreme sand production may also cause catastrophic fa d productivity and/or excessive maintenance of both downhole and surface equipment. Extreme sand production may also cause catastrop he field. Introduction A rock mechanical analysis for the Gj�a field (Figure 1) has concluded that all the wells will require some form of sa on by McDiarmid et al2 led to a conclusion that the failure was caused by high stresses in the reservoir compared to the formation strength. m entering the wellbore. Depending on vicinity-to-water reserves and economics there are three gravel-placement options. In the order of l

ese ESPs which were installed to sustain production rates failed as a direct result of sand influx. Since 1984 most wells in Sarir field have a later comparison of the results to actual field data and observations validated the analyses and methods used. The application and comp the field has been reported to have been experiencing sanding problems. For example the openhole completed well AA04 was reported to ot relate to each other and sand production may initiate before or after water breakthough (Sanfilippo et al. 1995; Skjaerstein et al. 1997). D

r describes the development of the model and the application of this model to formations from an oilfield in the Norwegian Sea. Introducti red for the study were obtained from laboratory and field measurements. The field data from five appraisal wells (study wells) were made a micals were developed to enhance acid diversion by increasing the viscosity of the injected acid. Depending on the viscosifiying agent thes after fracture closure.� However conductivity after fracture closure requires that the fracture face is non-uniformly etched by the acid wh and qualities. Even within specific areas and reservoirs the degree of heterogeneity is broad due to the depositional and diagenetic history

nnovate from lessons learned and experience gained from implementing over 200 treatments in the past few years mostly in the Khuff B an ing acid system to achieve diversion. This document discusses the results of the first wells treated with the viscoelastic diverting acid syste ommonly placed on carbonate versus sandstone matrix treatment fluid selection and optimization design. There are certain carbonate rese

al simulation of chemical reactions.17 However it will need a large amount of data not only on detailed mineral compositions of the targeted

on inhibitors can protect the tubulars at high temperatures only for a short period of time. These drawbacks make organic acids such as for

e acidizing.� The simplicity results form the fact that the rock is composed of calcite (CaCO3) and/or dolomite (CaMg(CO3)2).� Their r and underbalanced clean-up with coiled tubing are experiencing wide implementation in recent years but required further technological imp voirs is discussed. Introduction Carbonate reservoirs are routinely stimulated with acid to improve production.� Several experimental and ortant aspects of any restimulation program or attempt are: (i) learn from existing experience in the field or area about restimulation and form Lehman et al. Case studies of two wells are presented on this paper. On the first well after a pressure build up on the Muddy Formation tha

sate) VIII2 and VIII3 (gas-oil) and VIII4 in the Callovian; IX1 (gas) and IX2 (gas-condensate) in the Middle Jurassic; II-T III-T and VI-T (ga

rvals and place the stimulation fluids precisely into the oil bearing intervals unless the entire completion is pulled out and each particular inte via the cemented annular space means expensive remedial cement squeezes to cure the problem. The expense is considerably higher if t ow test. In contrast the buildup period is the one when the downhole valve X is closed and the wellhead valve Y is closed. The closing of th rogram is a 2 270 ft long horizontal well targeting an area interpreted to have high fracture density (see well schematic in Figure 1). The mai formance of multi-fractured wells. From a performance perspective the optimum production and completion would be the one that results i ilished as a preferred testing technique in this complex reservoir environment. e tests in both systems i.e. fractured and unfractured reservoirs is performed using Tiab’s Direct Synthesis (TDS) technique for analyz e flow period of a transient well test. This definition is not completely accurate when we apply an instantaneous source during which pressur arge numbers of ESP wells a time snap of reservoir properties could be periodically obtained to track changes in pressure skin and permea 1965; Kuchuk et al. 1990; Thompson and Reynolds 1986; Baygun et al. 1997). A thorough review and list of the previous deconvolution alg

ed at a number of rates with the above mentioned tests so as to be able to estimate the non-Darcy flow coefficient by separating the mecha ntinuous efforts have been deployed over the years to further develop Abu Al Bukhoosh resources in response to the growing maturity of th ater in gas and condensate wells. The need for inline measurement has been made more acute in the last few years to tackle the following

mit of liquid flow [or gas volume fraction (GVF)] though the accuracy of this approach decreases with decreasing GVF. The accurate determ se well test data in identifying and evaluating various well performance anomalies and how the measurements are used to monitor well prod

mon technique used in the industry to measure flowrates is the Venturi (or differential measurements); all manufacturers are using one or s mulation models using numerical well testing . The authors pointed out the difficulty in history matching during a simulation study due to the

d band-pass filters which exaggerate high frequency noise and distort the true dp/dt curve. The data is typically smoothed by subjectively ch ion of the casing was imperfect but functional as indictated by field test results. Horizontal Well Sand Control Completion A second field e

¼D; this low permeability means that most CO2 will travel by diffusion a very slow process over the length scale of a meter. Cement with a h ularly relevant when it comes to analyzing the stability of long term underground storage or disposal facilities for determining upper bounds

rio is still a very immature technology but environmental concerns have slowed down its development and more knowledge in the area is re on process and flow properties in three ways: CO2 dissolves in the brine increasing its density CO2 dissolves in brine and reacts with wa and temperature conditions. These data serve as an input for reservoir models and decisions on the injection regime as well as decisions o onsensus from extensive research in the last three decades that rapid climate change is already happening that global average temperatu tmosphere. CCS is thus recognized as a promising solution to mitigate climate change.[ii] Along with capacity and injectivity containment is

ther with maximum allowable flow rate. The ERD well has a Down hole Instrumentation and Control System (DIACS) completion with tree be drilled to the west of 15/20a-6 well. Five attempts (wells 15/20b-12 12Z 12Y 12X 1W) were made but all were understood to have be

s conducted by Melhorn (1958). The paleontology petrography and geometry of northeast Illinois Silurian reefs were described by Ingels (1 CO2 fields in the United States Hungary Turkey and Romania have been or are being developed to provide an efficient source for enhance €œWhat is the porosity cutoff to make a well here? The answer is found over years of experience and the school of hard knocks. Typically a on production performance.�Results show that this technology will be very promising for application in medium/low permeability gas-con der low recoveries. Therefore suitable EOR methods need to be applied to extend the productive life of these reservoirs and increase their ected to substantially increase recovery in those layers. Since 1997 field development and operation has utilized this combination of GOGD

rofractures which were formed due to tectonic activities at later times. The tectonic activities are principally factors making strong and wide - an increasing water production figures was identified as a good candidate for such approach. A temporary straddle system was created u etions only a pressure test can be performed to confirm that the perforations are squeezed off. This paper addresses the planning operatio

are located in the south end of the field that in recent years has experienced a surge in water production. Most of the wells in this particular nsile and compressive loads required at the packer during the operation are within the string capabilities and limitations. The friction coeffici

. Being able to predict the presence and type of trouble zones and dealing with downhole problems is increasingly important as water dep eometrical arrangement of the phases in the pipe. The flow patterns differ from each other in the spatial distribution and the position of the in n on the intermediate flow patterns which lie in between stratified and fully dispersed flows. In this study the gradual flow pattern transitions en fully open to completely closed.�The artificial lift system is also part of the control devices as for example the production rate can b ting oil and gas companies have started to address this problem and have started to organize multifunctional teams to better analyze their a sue during the life of the project. Introduction The size of the potential reserves drives initial capital expenditure and reservoir appraisal is n these heavy wax components are often calculated by extending the correlations for lighter hydrocarbon components. As such the model stry than commonly perceived. It attacks in one form or another all components at each stage of every hydrocarbon producer. Corrosion c tion. Since then other generations of the DFA tools have been introduced to obtain additional reservoir fluid information. DFA tools today ar

at is a function of a selected reservoir pressure initial stock-tank oil gravity specific gravity of the original reservoir gas and reservoir tempe n exist in both liquid and gas phases under reservoir conditions.� It also assumes that the liquid content of the gas phase can be defined y identification of fluid gradients [9 10] and compartmentalization during the Exploration and Appraisal stage.[2 11] DFA is an objective and a s (such as solids precipitation or significant liquid dropout) which can significantly alter well productivity ultimate recovery and project econo blem is “where injections fluids such as gas and/or water go. The industry’s standard procedure to delineate compartmentalization

omplex WFT probes which have recently become available. Introduction In the development of deepwater prospects and other capital-int

of sweep efficiency in mature reservoirs. Low porosity/low permeability sections can be more challenging to evaluate and these sections c ced is crucial. It may mean higher processing fees or a lower price for the oil or gas. It may also determine if it will be possible to access ex

ozabadi 2000a and 2000b; Firoozabadi 1999). Irreversible thermodynamics appears to explain compositional grading in most systems. In th th the rest of the column. The range of API gravity in a trap initially reflects the maturity of the source rock kitchen during trap filling constra ation pressure gradients obtained from wireline formation tester (WFT) tools greatly help in identifying fluid types. valuation is inadequate to determine the magnitude of fluid compositional gradients. Even multiple sampling with subsequent laboratory an radient analysis with reservoir fluid and thermodynamic models. However such an approach requires good data quality control and data ana ds often exhibit significant continuous variation of hydrocarbon components with depth. This has been illustrated in the literature [3] [4] [5]. mud filtrate is critical for the collection of representative hydrocarbon-fluid samples in wells drilled with OBM. The hydrocarbon sample may b

ous through the hydrocarbon intervals down to the water-oil contacts. Flow barrier locations would be found on the basis of anomalies and d ow a continuously increasing absorption at shorter wavelengths. This absorption (or color) is caused by the higher concentration of aromati e fluid property information during formation testing.1–10 DFA helps ensure that representative samples are obtained and allows an unlim

pear.� If the oil is light such as a light olive oil or sewing machine oil then the oil will probably vaporize first.� On the other hand if the choke valve or orifice) a stable emulsion can be formed. Presence of inorganic solids such as sand clay and corrosion products together

ction strategies are crucially dependent on knowledge of phase behavior and multiphase fluid flow and they rely increasingly on numerical g additional big volume fluid samples. The fluid analyzer also served as a warning device to indicate if there was any undesirable gas-liquid e and until now only two approaches were possible: using published correlations to estimate oil water and gas properties. This simple app multiphase well testing. The consistency of the multiprate well test information is not covered in still paper as the analysis of some condens The two main organic acids that are frequently used in the field are formic acid and acetic acid (Harris 1961; Smith et al. 1970; Chatelain e ffect two actions are necessary. First it is very important that the quality of the injected water is controlled since presence of iron compone ns (rate of dissolution) to generate wormhole structures. �Wormhole formation depends on the bottomhole temperature and pump rate u riodically frequent treatments necessitate well intervention and cause significant production deferment. This is further complicated with the

ation experiment as well axially through a restricted endplate simulating a perforation entrance hole. The experimental set-up in the authors a “damaged zone of fractured rock grains extending a distance of order 20mm from the perforation tunnel.�For liquid-saturated rock ½ï¿½ï¿½ï¿½ï¿½ï¿½Mixing of incompatible waters. Carbonate scales and in minor case some sulfate scales are without exception the inorg pped fracture (as opposed to a squeeze treatment which only penetrates into the critical matrix); have thermal stability at formation tempe

sses. With more than 400 producers and more than 350 pressure support water injectors in UZ a solid Well Integrity Management System ere are 32 well slots of which currently 15 are for producers with a further 10 wells dedicated to water injection.�From the outset it was r dual well history matching. In this paper we briefly present the theoretical basis of optimally delineating the regions in a reservoir for efficie

ement in simulation turn-around time that generally results from simulating very large often multimillion cell geological models incorporating g in terms of extra oil recovery by the use of this IOR technique. This is due to the specific imbibition/re-imbibition capillary hysteresis spre y smart completions that involve large investments and an early vision of the automatic production surveillance system for the entire asset l in the target reservoir units 2) qualitatively assess the impact of injected fluid fluxes vertically across low permeability sub-units within the re ore moderate-permeability shallow-water ramp-carbonate the Mauddud. These reservoirs were normally- pressured at the time of discovery echnology implementations have been significant over the last 10 years particularly the use of horizontal and multilateral wells and the deve to efficiently produce and procure the proper facilities for thermal operations. eated directly up to the high temperatures usually required to achieve total pyrolysis. However microwave-induced pyrolysis is possible if th

ng basins in Sudan is closely associated with the global phenomenon of plate tectonics and particularly with the separation of Africa from S interbedded evaporites suggests restriction was occasionally sufficient for the development of hyper-saline lagoons and sabkhas. The shal ophisika Logging unit due to the field remoteness) and wellbore conditions (well bore stability and high mud filtrate invasion).� Introducti

ba reservoir that is crucial for blending and transporting the heavy oil from Bentiu reservoir through the pipeline. Seven horizontals have bee

resulting productivity are mainly related to fracture density and sizes. When fracture density is minimal these reserves are developed therm

one formations. These formulations typically referred to as mud-acid are usually composed of hydrochloric acid (HCl) and HF at various c fluid mobilities and NMR permeabilities acquired in one of the exploration wells is also shown in the paper.

te the temperature differential needed to make thermal effects (i.e. convection) dominant. There is abundant information in open literature

g from shear in the tubulars and perforations.� Crosslink the fluid too early and the friction in the tubulars will rise significantly and as it w off through the walls of the fracture then reacting with the carbonate matrix.

s at depths up to 14 100 ft TVD Naturally fractured Basement which is up to 14 800 ft TVD The primary target is the fractured granite bas s developed to effectively treat multi-layered high temperature (200-375oF) reservoirs with long production intervals and complex mineralo ove damaging aluminosilicate minerals and reduce the skin value. The precipitation of silica is thought to be the major reason that sandston ly a marginal return on their investments. In an effort to increase productivity the hydraulic fracturing technique has been adopted since ma y addition of volatile solvents. Successful cases have been reported in literature where solvents have been used to clean up water and con y scale inhibitors when needed or both. Correct water resistivity is important for interpreting openhole wireline logs accurately. In addition a

d demand has launched tight gas as an increasing source of energy. A recent gas presentation sourced Wood Mackenzie as stating that in 2

ventional completion method. Additionally initial and refracturing of wells with 10-15 year of production history as well as fracturing of sidetr o actual fluid movement 13 14 and in some cases indicating a volumetric hydraulic fracturing process 4. Recent efforts have been given to

M-1. Production started on June 2001. In the same year one well was drilled in the reservoir D but due to very poor reservoir characteristic rticular because the technology has proven to be an effective stimulation method to increase well productivity from horizontal wells that are estone interval with minimal consideration given to the low productive low permeable 0.1 to 5 md Ratawi Oolite section. The Ratawi Oolite ntly upscaled into a dynamic simulation model. This flow model is calibrated against historical performance and used for forecasting wells a ah with a small portion in northwest Colorado.� This basin is a major depositional basin that subsided during late Cretaceous through Te ment. The thickness of individual sand units ranges from 5 to 50 ft. These geological heterogeneous reservoirs are poorly correlatable over ited and bypassed on an ongoing basis. In tight clay laminated gas sand basins one technique that the completion engineer often uses to

few years has caused a significant change in perspective with regard to understanding reservoir rocks and fluids and their heterogeneities ction to date of 5.4 billion barrels or 13.2% of the OOIP this field is one of the biggest hydrocarbon fields in the world producing from Camb outh Central Wyoming Regional Geologic Setting (Ryder R.T. 1988) Improving recovery in tight gas reservoirs mandates equally tight wel

ea from the mud column therefore allowing hydraulic communication between the flowline and the formation without influence from the mud elped to define the optimum waterflooding patterns from the beginning to avoid drilling more dry holes. The southern area is waterflooded p

Vendian units of the YTZ was developed. It was deemed that the basis of the YTZ is constituted of main massive deposit associated with a

ortance of changing wettability; the transition zones are often increasingly oil wet towards the top. It has been reported that a reduction in oi

n oil demand rise in oil prices and geopolitical reasons have necessitated the technological breakthrough’s in understanding of the res

ues or heuristics lead to high quality decisions however they are often polluted by individual biases and predictable mental errors. In the c ages an oil and gas exploration and production project in complete isolation. Memory biases influence how we remember and recall certain

l to successful reservoir management as reservoirs mature and enhanced recovery methods are planned and implemented. In addition m nt scales. Detailed reservoir characterization is needed to better map the formation heterogeneity for reservoir management. Core experime mary (e.g. interparticular porosity) and secondary (e.g. dissolution vugs or fractures) porosity could then be distinguished and this technique osition ranging in age from Late Carboniferous to Holocene stretching from onland to offshore to deepwater. The basin is divided into sub b

GOR CO2 content pH density viscosity and PVT behavior are key inputs for surface-facility design and optimization of production strate thermodynamic changes (such as solids precipitation or significant liquid dropout) which can significantly alter well productivity ultimate rec ethod may have to be resorted which can explain the production behaviour. The pore system classification would also help in designing a wa hin the reservoir. Using single well predictive modeling the flow units and the petrophysical rock types were defined and the water saturatio ment device capable of producing 16-sector gamma ray images as well as quadrant and average gamma ray measurements is located on porosity distribution and type within a reservoir is the first step in order to accurately quantify reserves and design proper field developmen

stitial water and considered the rock as insulator. In the presence of shale the rock becomes conductive and adds excess conductivity to the sidered the rock as insulator. In the presence of shale the rock becomes conductive and adds excess conductivity to the interstitial water con ure capillary pressure data and pore-throat size distributions. These three forms of rock typing can be supported by the workflow presented i m dipping sequence with dip azimuth towards Southwest. Fracture analysis is one of the most important objectives of borehole imaging in t uence stratigraphy which recognized multiple transgressive system tracts and high stands was based upon recognition of grain size trends g tools. The acquisition of new technology logging services such as tri-axial resistivity high resolution oil-base borehole images and nuclea

eful references that will not be re-quoted here. This paper is the third and last in the series. We will show the thin beds workflow using both

al (2005). Similar patterns in production profiles with high initial production rates followed by a sharp decline have been observed across t fluid profiling stations. Mitigating the impact of mobilized solids and sand grains on formation testing and sampling operations is essentially ore Formation MicroImager (FMI*) provides electrical images that are almost insensitive to borehole conditions and offers quantitative inform n the Al-Khafji where a number of wells have been correlated and calibrated with the Tayarat Formation. In the exploration area to the nort

ns in the twentieth century (Efron 2004). In geoscience and reservoir engineering however spatial statistics has seen more extensive applic ar real-time before the wireline formation tests started. The petrophysical solution was to combine GR Spectroscopy with formation density on tool. Permeability of the sand layers was also computed and compared to that of nearby thick sands. Core data in one well was used to v

dients in the reservoir are small stress reorientation in the reservoir is small. However in high rate wells low permeability reservoirs infill pr

ation stresses play an important role in geophysical prospecting and development of oil and gas reservoirs. Both the direction and magnitud

sition relationship are given in terms of consistent units for slightly-compressible liquid flow analyses with Eqs. 3 through 5 for time flow rate

of Thebes and Mokattam Formations. Since this well NWO-1 was drilled over the peak of anticlinal structure therefore natural fractures wil ent carbonates and weathering crust. Further investigation on Pre-Jurassic reservoir of the SE West Siberia showed that production potent minant NW-SE strike direction consistent with the trend of the major faults interpreted from the seismic data. The majority of these faults are rther investigation on Pre-Jurassic reservoir of the SE West Siberia showed that production potential is mostly related to the basement lime

is the third phase introduced into a two-phase system thereby reducing the relative permeability to gas. This usually results in longer clean

s that can be found in the productive formations of the region (i.e. Huamampampa Icla and Santa Rosa). For e-log interpretation purposes eability k to select test points at the most permeable zones. However what are missing are continuous hydrocarbon type and properties lo

œeveryday NMR in a recent paper (Akkurt et al SPE 2006). Among the recommendations listed for everyday NMR was the use of T1 loggi nts is that they are extremely flexible and can be tailored to fit many different formation-evaluation applications.

ormations.

as temperature and flowing wellbore pressure are continuously measured while drilling which is not always the case. By applying inverse m ith-Shuaiba period; mainly EW faults crossing the field in its central part during the Shuaiba-Ahmadi period; small NS faults in the north EW

In recent years formation sampling and testing tools have seen the introduction of an array of downhole fluid property measurements. Thes ition of downhole fluid samples accompanied by a real time fluid analysis (DFA) while sampling. One of the methods available for downhole position relationship are given in terms of consistent units for slightly-compressible liquid flow analyses with Eqs. 3 through 5 for time flow r y in the western part of the field are “tar-mats comprising 10-20ft thick highly viscous oil layers; simulation has confirmed that these ta hole evaluation stage. As noted these conditions are quite challenging for formation testing. Some of these challenges particularly near we

etermine stress direction and magnitude including the use of acoustic logs. However they do need to be calibrated by direct measuremen erpretation would be overtly complex. We have developed a software tool which presents a workflow to analyze data acquired with single o k from the remaining uncertainty allows us to make informed investment decisions. An ideal FDP should not only include recommendations more complex and pressure data –both from wireline formation testers and production tests- is an essential item required in order to deter ESP technology and techniques to engineering teams and operational personnel for this first ESP installation in Malaysia The inception of of 470 sq. Km all onshore. Oil and gas has been exploited in Block 10 since the early 1910’s mainly from formations of Tertiary age ly development began in 1982/83. The cumulative production of 170MMbl of oil has been produced to date through 47 wells with 97 active pro

production from 12 zones ranging in depth from 2 800 to 10 600 feet.�Most prolific of the zones are the Grayburg and San Andres that equirements Fig. 1 illustrates the nature of such hydrocarbon accumulation by means of an offshore oil field which spans vertically about 5 ous oil production rates. Figure 1 shows a cross section of a typical thin oil rim reservoir. Fluid breakthrough has a different effect on individ atural depletion with reservoir temperatures range from 280 to 300 �F and 22 �API approximately. The field development currently con aper presents a comprehensive set of tools algorithms and frameworks (referred to with FM or FM framework in the following parts of the p remedial operations to mitigate flow assurance issues. During the Operations Efficiency cycle daily monitoring and surveillance activities t at the present time no infrastructure such as a compression system or offshore water treatment facilities is available on the platform. Majo m. Three “Revisit campaigns were conducted on the Betty field. The first in 1984 drilled 5 additional wells. The second campaign in 19

ed to the surface facility model. The well model surface boundary condition acts as sink or source term in a surface network which has to b ptimization operations surveillance & asset planning to uncertainty analysis and fiscal determinations. However existing work flows and ap ting oil and gas companies have started to address this problem and have started to organize multifunctional teams to better analyze their a e to a model that is acceptable within all imposed boundary conditions. History-matching is in many cases the most time consuming task in ut also causing rapid water breakthrough in high permeability layers. The shallower formations are prone to sand production so the typical

er contacts (OWCs) have significantly encroached upward leaving thin remaining oil columns and causing high water production from all of productivity and a better understanding of the factors impacting productivity layer-by-layer in the Barik and Miqrat formations. Introduc o-pressured. Economics dictate the need for hydraulically fractured completions and commingled production from multiple zones which com onal probabilities and Monte Carlo simulation such that the future information is appropriately valued today. Such a valuation is intractable u

trical anisotropy and bed boundaries (polarization horns) and read deeper than azimuthal laterolog measurements (a few feet) but this tech he Outer Moray Firth Basin. Between 2003 and 2005 several vertical appraisal wells were drilled to determine the potential of developing th s this prior work.� Introduction The current study is a pragmatic approach of linking disparate activities which collectively can have a pro er sand-dominated depositional events a fine shale layer was deposited that separates the Upper B4 from the Lower B4 reservoir horizon. � However the critical aspect is if bypassed reserves remain in significant amounts to be economical given the lower investment required the initial well placement study. In parallel geosteering feasibility assessment was conducted and tied to the reservoir simulation results. T ach iteration and requiring many forward reservoir simulations. A rather different approach is proposed by Lui and Jalali (2006) where stan

flow characteristics of sand filters. This combined with the equation of continuity and an equation of state for slightly compressible fluid giv effects and interference between wells. There is clearly a need for an alternative technique that allows very fast model building and executio es in existence uniqueness and stability. To remedy these problems a regularization term in the form of data-independent prior informatio model for the field. Thus any reduction in the time taken for this phase is very important to speed up the modeling process as the majority

istent with the geology in true sense. Most of the work done on this aspect considers the covariance as a measure of geological consistenc

atical Formulation The thermal model described here is based on the assumption that Darcy’s law and instantaneous phase equilibrium tion formulation (IMPSAT). Furthermore different implicitness formulations may be applied to different cells which is referred to as the adap pleted interval may not contribute to production. For some horizontal wells only a small portion of the perforated interval produces. Practice

e areas with limited platform capacities. A typical horizontal well has a large perforated interval and produces from multiple formations. How

e forced to close by flowing back some of the fracturing fluid at controlled rates to prevent disturbing the proppant pack significantly. As a re d. Following the fracturing treatment a typical tight-gas well achieves its maximum gas rate within a few days after stimulation and then ex nd 7 - similar to zone 2 and 3 in being tight are best completed with selective fracture stimulation treatments. A well in this reservoir was se sary to predict the performance of hydraulically fractured well in gas condensate formations. The different approaches are being used for g ure height growth. It has also been shown that fracture growth can be arrested by weak interfaces when the effective normal stress across ncertainty. The most common way of estimating post-fracture production has been to use analytical software such as nodal analysis softw

non-linear regression method2 proposes the use of a multilayer analytical simulator (forward model) coupled with a non-linear regression alg essure ) and the classic transient testing dimensionless wellbore solutions for pseudosteady state flow expressed in terms of the pressure able fracturing models were matching with the observed pressure responses. While pumping such jobs the net pressure was high and alm st provide some recommendations it is necessary to establish fracture initiation mechanisms then estimate conditions resulting in different iences and petroleum engineering including permeability prediction (Aminian et al. 2003) fluid-properties prediction (Sultan and Al-Kaabi 2

d b show the location of South El-Manzala (SEM) field. South El-Manzala field is dissected by ENE striking low angle dip-slip fault that was length of the well. Even with coiled tubing there are practical limits of how far the well can be logged (e.g. currently of the order of 1 to 2 k

d production data measured PVT properties and average reservoir pressure. Usually it is expected that oil and gas production are measu

ffect similar to that in a thermogravitational column (Ghorayeb and Firoozabadi 2001; Nasrabadi et al. 2006). The combined effect of conve distilled from the application of ED and RSM concepts to 15 detailed reservoir studies and at different points in their project maturity spectr

ith a single control volume (e.g. see [9]) transmissibility upscaling procedures apply to a boundary between neighboring control volumes an

ral publications2 3 have addressed the recovery of oil from vugs that are connected to the fracture system. This work concerns isolated vu ng questions raised. In this paper we focus on the modeling of shear fractures which are generated by structural deformation accompanied

her very large (parallel) computing effort or coarsening the model through upscaling. Time step length has to satisfy CFL condition for the ex mpressible dual porosity simulation have been observed. At the same time the possibility to further improvement of the computational effic are stored in matrix blocks and flow occurs in the fractures. It is recognized that state-of-the-art simulation methods based upon dual-porosi

The PUNQ-S3 reservoir represents a synthetic model based on an actual reservoir (Floris et al. 2001; Barker et al. 2001). The problem was

f sea water which is rich in sulphate ions is injected into a reservoir with formation water this is rich in barium ions then barium sulphate m

ing a frozen velocity field. As the name of the method suggests the 3D transport equations for saturations are transformed into a set of 1D modynamic characteristics and equilibrium surfaces. This requires the fulfillment of numerous iteration processes during the calculation ste ng these opportunities in real bottom line results. The goal of the study is to generate sound technical arguments to formulate an innovative

e data with the recorded pressure data are compared. Such dominating patterns can be extracted by means of a mathematical tool called s within a well. Thus while flow in an annulus could be modeled the well segment topology had to be such that there was only one flowpath

a respectively. Reservoirs flow properties range between fracture to matrix dominated flow. Based on available fluid sample analysis from

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½(2) Eq. 2 is commonly known as the Forchheimer equation. In the discussion of elow the oil zone the location at which oil saturation becomes irreducible) SOR (as depth increases below the oil zone the location where was to be conducted through the production tubing to access the by-passed hydrocarbons. The Thamama Limestone group is highly fractur aningful results that could be used to formulate a drilling program one of this being the stress orientation of the area. This is a significant an ip fields where many but probably not all of the Smart Field Technologies have been deployed.�The development and deployment of th

States federal lands and waters north of the Brooks Range foothills which have been explored to a greater or lesser degree. The ANS ext s paper. Both types of models assume a linear-elastic mechanical behavior. Therefore the response of the cement sheath to strain is dete

ff operations successfully increased the oil production. The purpose of this paper is to demonstrate the potential of the through-casing resis pletion solution integrating flow control of the lateral and main bores together with natural gas lift was implemented on the Troll and Vestflank he field. Studies indicated that water flood with artificial lift would significantly improve the oil recovery in the Mauddud Formation. The focus with a new much more powerful tractor.� Examples using both types of conveyance are given here. Production log interpretation in hori

hese are low permeability rocks drilled with oil base mud containing oils that are very close to saturation pressure. We therefore have to de

the sampling technique and the type of drilling mud used in the reservoir zone. Oil-based drilling muds will usually provide good-quality wate t on other dependant variables to allow an optimized production management loop. In other words “smart well data develops a new inte hydraulic fracture stimulations are complex and frequently monitored for induced seismicity (Cipolla et al. 2005). We have analyzed one h 00mD) and unlock its large reserve base in the low-permeability (0.001 – 1mD) Cambro-Ordovician reservoirs specifically the Quartzite o

their Joslyn field in 2004 as Phase I of the reservoir development. During the completion of the SAGD pair of wells in Phase I a fiber optic be considered in evaluating the transport capability of a system for moving liquids upward in the well.�� These are the criteria for mov g the transport capability of a system for moving liquids upward in the well. These are the criteria for moving the liquid film along the wall of on causing incorrect temperature log interpretations while the well is responding to transient shut-in effects. The introduction of permanen

s introduces the same type of uncertainty because of varying flow conditions as found in the test-separator method.

eed to be included in the Production Target definition. The answer to the second question is more complicated as it needs further investigat ses in stratified flow. One approach used is a bulk tracer or radioactive marker technique that is only sensitive to one of the phases anothe throws considerably larger than the Mauddud thickness. In the past SBHP and pressure transient data have been acquired at some wells and pressure conditions.� They may start to precipitate once the stability of the colloidal suspension is destabilized which is caused by ne the wells in the field of scope and show how we were able to optimize the well recovery. 1) FIELD GENERAL INFORMATION NR field w pletion and communication information whereas others may seek information on the precise nature of the hydrocarbon fluids and water in t LT) log which again results in loss of production because the well is often shut-in for some time and also needs to be flowed at a reduced r hat respond to different expressions of geomechanical deformation associated directly with steam injection. In some fields this geomechan servoirs are part of a multilayered sandstone anticline with approximately 5 billion barrels of reserves in place. The field’s north flank dip when 1 467 wells were installed. A large percentage of these subsea wells will require sand control and multistage completions. Despite th

other side of the process from wellhead to production separator to reconcile both data sources and detect any production measurement e ntal flow environments specifically wells with loose sand and/or debris that potentially damage sensitive spinner and probe sensors are not

onitoring and maintenance enhanced/improved oil recovery evaluation of bypassed oil identification of fluid movement etc. depends prima

ng the surveys in a time-lapse mode. As part of this project lab tests were conducted to choose a material that would limit the attenuation injection saturation and pressure data will be used to calibrate the simulation model. The ultimate goal is to design an optimum field devel 10 years. Wells in this basin are now trending towards a much higher percentage being cased and perforated multizone completions rather gth fractures are classified as butt cleats. As a result of geometry and connectivity variation significant face and butt cleat permeability aniso eams are highly susceptible to near wellbore permeability reduction damage or skin. This is either caused by invasion damage from the drill treatments. Before 1997 Barnett shale wells were completed with massive hydraulic-fracture treatments consisting of crosslinked gelled fl tment (e.g. low pumping rates are insufficient for carrying proppant).� Small stages of high viscosity fluids may then be used to facilitate

commodity prices.� By 1996 the well count exceeded 300. In 1997 Mitchell Energy began to experiment with Slickwater stimulation treat and Frantz et al. (2005). In order to achieve economical production and enhance productivity a large number of horizontal wells have been y examined several completion strategies and our simulation model calculated the impact of these strategies on oil production and SOR in t edded with the shale through natural fractures or from the shale matrix itself. In some cases natural fractures are healed by a mineral fillin f new wells where the technique enables stimulation of larger wellbore intervals when used in the same fashion as for re-fracture stimulatio als rather than the matrix framework itself. Hence the framework of the sandstone is not significantly altered by the acidizing process. Since

Meanwhile the high pressure and appreciable velocity air leaving the venturi tube drives an Air generator which produces power. This powe S and JS reservoirs). It contains more than 50 distinct oil pools. The reservoirs consist of terrigenous rocks of continental and shallow-water

the number of layers fractured during a single stage. Stimulating multiple layers in a single stage is not ideal since layers with lower fractur the production test showed a 3-fold increment in production compared to the previous best producers in the field. The skin estimation base cessarily restricted to use for vertical wells only.� In spite of this fact it has been noted that laboratory experiments have clearly demonstr cessarily restricted to use for vertical wells only.� In spite of this fact it has been noted that laboratory experiments have clearly demonstr of this project was to drill a tri-lateral well for maximum reservoir contact in an area where fracture density was interpreted to be low and ther

concept of locating missed pockets of oil goes back to Hurst (1979) and the concept of controlling production was suggested by Rinaldi (19 ed to efficient realtime production optimization.

veness of these fluids making it impossible to perform matrix acidification when an ESP has been installed with a conventional completion utline of the three main classes of SA methodology. We define terminology; in particular the terms “system and “components. We

ermine the impact on well performance versus continued use of diesel based frac fluids. Various fracture fluid systems were reviewed and a

e Field. The “Bar Trend is a very consistently developed thick clean dolomite zone of 5 to 16 feet with porosity development of 5 to 14 p proppant fracture treatments are typically pumped. These fracture treatments are carried out with low polymer concentration non-crosslink

e scope of fiber application has vastly expanded with additional benefits of degradable fiber-laden slurries being realized as application exp d reduce the drawdown to produce. In practice it is understood that oil and gas reservoirs are very complicated in their wettability. Almost ne ates of hydraulic fracture geometry are available. It has been observed that sometimes the fracture is more contained in height than predict duced waters by recycling and using them as completion and fracture fluids. Time on location and cost of associated equipment is always a ses for flowback water in the E&P industry is both an economic as well as an environmental issue. In an effort to circumvent some of the ex es were introduced to further understand the production enhancement opportunity.� This paper focuses on three major formations (Figur m to achieve better zone coverage. After the treatment was performed a screen was washed down through the gravel remaining in the cas en outs. The fracture height growth out of the pay zone and the reduced proppant mass placed because of the premature treatment termin osts. Since the oil could not be recovered economically work to develop these reservoirs was suspended for not saying abandoned. In 200 y several stacked reservoir that initially had different pressures regimes but presently most of them have the same sub hydrostatic pressu nstructed at comparable costs to vertical wells while offering the advantage of higher production rates and better access to reserves. Often t

y in future applications.

nhole will be diverted into each layer depending on the resistance to flow. Depleted intervals low pressure intervals and intervals that fract This leads to early packoff before the desired volume of proppant is placed in the fracture. In the second case when TSO occurs too late th he encapsulated material uses a polyelectrolyte to disrupt the surfactant micelles and lower the fluid viscosity even in dry gas wells where

n4 to see several vertically discrete sandstone reservoir zones in a single well where sandstones may have different trends and detrital and

osition within the reservoir in addition to accelerating oil recovery. One viable approach is to improve oil production. Improved oil production roduction for a long period of time. However the existence of yield stress effect remained controversial until the first publication9 resulting fr ars and lagoonal muds.� Storm cuts and organic burrowing also characterize the depositional environment.2� The thickness of the Co

he absolute fracture azimuth may be considerable even for wells only slightly deviating from expected positions. Fracture geometry (mainly i

fracture faces may be crushed and eventually at high closure stress the lasting fracture conductivity may depend more on rock strength t ds and Reservoir Description The Priobskoe field one of the largest oilfields in the world is located in Western Siberia. The reservoirs unde mation interval. Although this analysis gave indications of which parts of the interval had accepted fluid it didnot give the desired information

ilable testing practices was necessary. Also the methods of determining reservoir pressure fluid composition and production prediction th ctivity in single-phase flow:stress on the proppant and type of proppant. Thus apparent proppant permeability will vary with distance fro

andidate for acid fracturing treatment. The K-formation is also classified as a moderately permeable to tight gas reservoir which has a poro

gle observation well such that the seismic radiation is measured only in a limited direction. This limited sampling of the radiation pattern cer

ection causing the fracture to turn towards the original fracture orientation as illustrated in Fig. 1. Siebrits et al.3 further extended this work ion and growth were based on either Khristianovich model [1] or Perkins (PKN) model [2]. Both models rely heavily on the elastic (or poroe ons to 150-300 tons1. The proppant size has also been increased to enhance conductivity sometimes using sizes as large as 10/14 mesh.

n-up behavior. Special effort was undertaken to identify and measure directly any flow initiation gradient (FIG) or yield stress effect. A mod a subsea production system back to a Floating Production Storage and Offloading (FPSO) unit. Water injection was required from day one ection rates improvement in the selectivity of water injection profile reducing of wells spacing in fields borders and specially a massive cam studies10 11 were concerned with proving that hydraulic fractures could cross natural fractures in their path. Later studies were concerned d at the time of writing of this paper the majority of them in the Scandinavian sector of the North Sea. Various papers have discussed applic ds. C&P-1 Well: This well was completed in June 2002 targeting 23U/L & 24U-sands in Amherstia at a measured depth of 12 290-13 566se advancements to such an extent that drilling thousands of feet through a thinly bedded hydrocarbon reservoir is not a challenge anymore e advancements to such an extent that drilling thousands of feet through a thinly bedded hydrocarbon reservoir is not a challenge anymore tones. These formations are classified into four main zones: D E F and G. The G reservoir is characterized by its low permeability. Its pro es range from 5 to 10 mD. Three-D seismic data show the Shu'aiba reservoir to contain a number of faults. These faults and fractures have e. It is concluded that Inflow Control Device proven technology is beneficial and successful in Bloque 15 Ecuador�� and its applicatio

al. 2002; Kharghoria 2002). Passive control may be effective if the reservoir geology and drive mechanisms are well understood so that inf o recreate fracture propagation observed at field scale even though a great difference of scales exists between fractures generated in labo

magnetic resonance (NMR) logs have been increasingly used over recent years to help determine an accurate reservoir pay thickness (Ref. he other hand high strength rock is not expected to sand and therefore does not require sand control. Reservoirs with rock strength from m ogeneity of the rock.� In a carbonate reservoir the heterogeneity occurs from the deposition and diagenic processes through the geolog which confirms the progressive erosion of the Devonian stratigraphic succession towards the east-northeast direction. The petrophysical c st producing well in Resak field with stable production at 49.8 MMSCCF/D. Introduction This gas producer well was drilled in March 2004 a its importance is often overlooked during completion operations. It was recognized that perforating was an area that could be improved in on practices to minimize skin effect from drilling and completion fluid invasion and by minimizing perforating-induced damage. Permeability ing from the initiated fracture into the PFP) at an achievable fracture initiation pressure. Table 1 shows the tradeoffs between different perfo pressure of more than 1000 psig until they had been acid stimulated. These wells often require several runs of perforating on wireline to c sess the quality of the completion. Pressure transient test is typically conducted in a way that surface flow rate is maintained in a constant o though these conventional methods are deemed efficient in the industry incidents that have a high impact on cost deliverability include P ctiveness of both job risk management and system development. An analytical model of perforating gun swell can help risk management in

tion as the case may be).

ent of the world's first Electric Submersible Pump (ESP) designed for use in ultra deep water. Due to the geological complexity (resulting fro

stry.1� Sand control measures in unconsolidated formations without impairing well productivity have been a challenging task from both te 0) ranging from 2 to 16 and the fines content from 1 to 15%. Overall the formation sands are poor to well sorted with low to high fines conten

ion option except in fine sand environments. Due to the need to control fine sand (D50 < 60 μm) without affecting the well performance e wash pipe for returns to surface. Such pressure rise can be problematic in cases where the operating window between downhole circulati

/oil-based drilling fluid (S/OB) due to advantages it offers over water-based fluids. These include higher rate of penetration excellent shale ction may also cause catastrophic failure of the wellbore and/or well and surface equipment. The production of sand is a worldwide problem roduction may also cause catastrophic failure of the wellbore and/or well and surface equipment. The production of sand is a worldwide pro he wells will require some form of sand control measure installed in the reservoir section to prevent sand production. For the long horizonta compared to the formation strength. The high stresses caused wormhole-like failure propagating from the producer to the injector. This cha -placement options. In the order of low-to-high skin the options are: Frac-Pack High Rate Water Pack (HRWP) and Gravel-pack1-3. Each

1984 most wells in Sarir field have been periodically cleaned as a precaution against sanding-related problems. AGOCO the field operato ods used. The application and comparison also disclosed that the approach was not only able to provide results that closely matched field e ompleted well AA04 was reported to have fill up to 1094 ft from TD in September 1971 in a period of 18 months. Sanding in the cased and t al. 1995; Skjaerstein et al. 1997). Despite these inconsistent field observations it is generally accepted that sand-production risk increases

d in the Norwegian Sea. Introduction Sand production is a common and very damaging problem in hydrocarbon production from clastic sal wells (study wells) were made available for this study. Mechanical properties of the reservoir sandstones and shales were established b nding on the viscosifiying agent these systems can be divided into two main categories: polymer-based and surfactant-based. Acid-soluble non-uniformly etched by the acid while the strength of the rock is still maintained at high levels to withstand the closure stress. At low closur e depositional and diagenetic history of the basin. Reservoir heterogeneity complicates every aspect of a well’s life from drilling to com

t few years mostly in the Khuff B and C reservoirs. The acid fracturing stimulation program has achieved great success in vertical gas produ the viscoelastic diverting acid system and compares their results with those of the conventional methods used previously. Discussion B n. There are certain carbonate reservoirs and completion scenarios that require an optimized fluid and placement strategy such as forma

mineral compositions of the targeted simulation zones but also on nature location and extent of the damage materials in the near wellbore

cks make organic acids such as formic and acetic potentially attractive for stimulating high temperature wells. Organic acids have been us

dolomite (CaMg(CO3)2).� Their reaction products are soluble in the spent hydrochloric acid.� However the physics and engineering a ut required further technological improvements. The gas operators in contrast have implemented hydraulic fracturing mainly in mid-temper uction.� Several experimental and modeling studieson the response of carbonate cores to various acids under varying conditions of injec or area about restimulation and formulate a reservoir specific selection criteria that will capture the key ingredients for the success of restim build up on the Muddy Formation that showed lower than expected reservoir pressure and permeability it was decided to fracture stimulate

ddle Jurassic; II-T III-T and VI-T (gas-oil) in the Triassic. Jurassic productive horizons are found at depths of 2179–2320 m and Triassic

is pulled out and each particular interval can be accessed seperately by using a straddle packer. This approach will not only involve the wor e expense is considerably higher if the communication problem is discovered after the well is drilled and the rig has left location. Because o d valve Y is closed. The closing of the downhole valve reduces the effective wellbore storage and increases the chance of capturing the data well schematic in Figure 1). The main purpose of the well is to understand the contribution of the fractures and determine to which extent th etion would be the one that results in the maximum economic benefit to the operator. In practice the optimum completion design and opera

ynthesis (TDS) technique for analyzing log-log pressure and pressure derivative plots. TDS uses analytical equations to determine reservoi aneous source during which pressure may diffuse to a long distance. Therefore to understand the radius of investigation first we look at the hanges in pressure skin and permeability for real time optimization. Introduction One of the main objectives of every operating company is ist of the previous deconvolution algorithms can be found in von Schroeter et al. (2004). The primary objective of applying pressure/rate de

coefficient by separating the mechanical skin component from the total skin factor (st ). All these multirate methods of interpretation require esponse to the growing maturity of the field. A remarkably wide variety of means and techniques have been deployed throughout its develop last few years to tackle the following issues: Mitigation of the carry over in gas line out of conventional separator Increasing need for high

ecreasing GVF. The accurate determination of liquid rates by wet-gas meters is restricted in range. The application and performance of mul ements are used to monitor well production over time. Introduction Accuracy of the flow test results performed by the existing test separator

all manufacturers are using one or several Venturi and most of the time coupled with a density nuclear measurement. The fraction measure during a simulation study due to the large uncertainties associated with reservoir properties in flow simulation models particularly for permea

typically smoothed by subjectively choosing the points used in the calculation a sufficient distance from the point of interest.11 Regardless o Control Completion A second field experiment utilized a 21-electrode array deployed in a horizontal well that was drilled in a thin oil column

th scale of a meter. Cement with a high w/c ratio however could have a much higher permeability less resistance to CO2 aggression and ilities for determining upper bounds to acceptable fluid pressure changes in both the injectivity at the well(s) and the storage capacity of a re

and more knowledge in the area is required. The second scenario geological CO2 storage is currently available through several commercia dissolves in brine and reacts with water forming an acid and H2O dissolves or vaporizes into CO2 removing water from the brine and incre ection regime as well as decisions on the monitoring of long-term CO2 migration after injection. ning that global average temperatures are increasing at unprecedented rates. In parallel CO2 emissions from anthropogenic sources hav pacity and injectivity containment is agreed to be a primary function in geological storage performance. As evidenced by oil gas and even

stem (DIACS) completion with tree separate zones operated by three hydraulically controlled flow valves. This is the longest DIACS comp but all were understood to have been considered at that time to be disappointing. The previous operator then decided to abandon any furth

an reefs were described by Ingels (1963). Joudry (1969) published research on potential dolomitization mechanisms in the Southern Michig ovide an efficient source for enhanced oil recovery projects. On average the global risk of encountering >1% concentrations of CO2 in a ga he school of hard knocks. Typically a “Rule of Thumb is used and a line is drawn (Fig. 2). Many South Texas partners make their decis n medium/low permeability gas-condensate reservoirs.� For actual field implementation a more detailed reservoir simulation study wit these reservoirs and increase their recovery factors. as utilized this combination of GOGD and localized waterflood1.

ally factors making strong and widespread alteration of basement rocks. The basement rocks have been fractured broken and catalazited orary straddle system was created using two through tubing inflatable packers therefore isolating the top and bottom perforated zones in or per addresses the planning operational and the learning from the through-tubing water shutoff campaign successfully carried out on wells w

n. Most of the wells in this particular area are experiencing water cut of 90% or higher. Problem Scope The main production challenges in s and limitations. The friction coefficients were estimated based on the available friction data in offset wells.

increasingly important as water depths increase. This paper describes a production assurance risk study based on asphaltene precipitation distribution and the position of the interface resulting in different flow characteristics such as velocities holdup profiles and pressure grad the gradual flow pattern transitions from stratified flow to dispersed flow are observed and characterized. The water holdups and pressure example the production rate can be reduced to avoid coning and establish production below the critical rate in the moment first signs of b tional teams to better analyze their assets to improve operations and optimize production. However proper workflows and technology must enditure and reservoir appraisal is limited in the case of marginal fields. Reducing the number of flowlines by commingling streams from se on components. As such the model prediction is generally not accurate. Quality experimental data are required to “tune theoretical mod hydrocarbon producer. Corrosion costs the American industry nearly $200 billion a year of which the oil industry picks up more than its fair fluid information. DFA tools today are used for such applications as: to evaluate downhole fluid sample contamination2 to measure Gas-O

al reservoir gas and reservoir temperature. The data set included laboratory studies of 190 gas-condensate samples. This is the first propo ent of the gas phase can be defined as a sole function of pressure called vaporized oil-gas ratio Rv (also referred to as rs2).� This functio tage.[2 11] DFA is an objective and a vision ultimately to provide a continuous downhole fluid log; it is performed by specific tools such as th ultimate recovery and project economics. In aging reservoirs fluid movements are of constant focus and routine cased hole logs are comm e to delineate compartmentalization is to determine pressure communication. Recent works have shown that a single pressure gradient iden

water prospects and other capital-intensive exploration and production projects understanding the nature of hydrocarbon fluids in terms of c

ng to evaluate and these sections can still have considerable hydrocarbon potential. Although OBM can be challenging for contamination q ine if it will be possible to access existing producing facilities or not and thus the feasibility of a project. The accurate measurement of H2S c

tional grading in most systems. In this study we will assume that thermal diffusion does not play a dominant role in distributing hydrocarbon ck kitchen during trap filling constrained by the capacity of the trap while the range of GOR and the bubble point of oil in a trap reflect the pr uid types. pling with subsequent laboratory analysis is somewhat risky because a variation of fluid properties measured in separate sample bottles mi od data quality control and data analysis since pressure measurement problems supercharging wettability effects and depth measureme ustrated in the literature [3] [4] [5]. With increased drilling in HPHT (high pressure high temperature) and deep offshore settings more and BM. The hydrocarbon sample may become useless if the contamination is too high (typically above 10 to 15% for crude oils or 1 to 3% for g

und on the basis of anomalies and departures of the measured data from the modelled pressure and fluid gradients. Introduction Composi the higher concentration of aromatic molecules and is typically larger for heavier oils. As a result high-density hydrocarbons which have a es are obtained and allows an unlimited number of zones to be evaluated in a “fluid scanning mode. The sampling program can be optim

ze first.� On the other hand if the oil is heavy and not very volatile then the water will boil away first.� If heat continues to be added to t y and corrosion products together with surface-active materials such as asphaltenes and naphthenic acids also enhance the stability of e

they rely increasingly on numerical simulators tuned to pressure/volume/temperature (PVT) laboratory measurements. The presence of co ere was any undesirable gas-liquid segregation in the tool flowline upstream of the sampling bottles. Determination of the drawdown thresh and gas properties. This simple approach leads to acceptable metrological results up to 1500 psia. The upper limit can be extended to 5000 er as the analysis of some condensate to gas ratio between chokes is still ongoing at this stage and will be presented in a separate article. 961; Smith et al. 1970; Chatelain et al. 1976; Dill and Keeney 1978; Crowe et al. 1988; Fredd and Fogler 1998; Huang et al. 2000; Nas ed since presence of iron components as well as other damageinducing elements such as biomass has been revealed on lab analyses. S mhole temperature and pump rate used in their execution.[Fredd 1999]� Sandstone formations are generally acid-insoluble (being largely This is further complicated with the availability of fresh or low-salinity water in some areas of the world due to the very large volume require

e experimental set-up in the authors’ laboratory allows the single-shot perforating of 7-in. diameter 18-in. length samples under downho n tunnel.�For liquid-saturated rocks the porosity (and density) of the damaged zone is close to that of undamaged rock; for gas-saturate cales are without exception the inorganic oilfield scales that are found in oil wells of Western Siberia. The most common scale deposits foun thermal stability at formation temperature and; have long lasting retention characteristics to ensure sufficient protection time. The efficie

Well Integrity Management System (WIMS)1 was put in place by ZADCO that helps to identify prevent and solve all the problems related t njection.�From the outset it was recognised by BP that the formation water / injection water mix would lead to a severe scaling tendenc g the regions in a reservoir for efficient history matching. The proposed approach is then demonstrated on three case studies. Description o

cell geological models incorporating highly variable heterogeneities and a long production history in very few hours (sometimes minutes)2 imbibition capillary hysteresis spreading coefficient ranges and high productivity characteristics of the Cantarell Field that will be discussed eillance system for the entire asset life.� In onshore brown fields however the implementation of automatic engineering workflows rema w permeability sub-units within the reservoir and 3) determine pressure support due to pattern injection. The pilot will also address the issue y- pressured at the time of discovery. al and multilateral wells and the development of artificial lift systems resulting in new production targets of 2 000 BOPD per well compared

ve-induced pyrolysis is possible if the raw material is mixed with an effective receptor of microwave energy such as carbon (El Harfi et al 2

with the separation of Africa from South America trend. This west and central African Rift System extends from the Benue Trough in Nigeria line lagoons and sabkhas. The shallowing-upward cycles are capped by mud-dominated rocks hardgrounds and exposure surfaces. The a mud filtrate invasion).� Introduction There are large reserves and resources of heavy oil present on the Eastern European (Russian) an

ipeline. Seven horizontals have been drilled out of which four of them are in Aradeiba formation and three are placed in Bentiu fiormation.

these reserves are developed thermally. The Nukhul formation is the only reservoir in the field that can be cold produced because of its hig

hloric acid (HCl) and HF at various concentrations. Examples of these traditional HCl:HF formulations include 6:1.5 and 12:3 mud acid syste

ndant information in open literature on examples of graded columns and analyses of the forces thought to be responsible for these observe

lars will rise significantly and as it will be shown later a significantly crosslinked fluid cannot be sheared without permanent damage to the

ary target is the fractured granite basement which is typically oil saturated with a gas cap. The secondary target is the lower Miocene and Ol ion intervals and complex mineralogy. The benefits of the new sandstone acidizing fluid which utilizes a novel chemistry include simplifie o be the major reason that sandstone-acidizing jobs fail to produce the anticipated decrease in skin especially at temperatures > 150�F chnique has been adopted since many years being in most cases the only method of achieving commercial production levels. A typical Sa been used to clean up water and condensate blocks.[1 2 11-13] However solvent based clean up is temporary as the well has to be retrea wireline logs accurately. In addition analysis related to various environmental aspects like concentration of organic compounds and heavy m

Wood Mackenzie as stating that in 2003 17% of gas was tight gas and 73% was conventional. In 2003 shale accounted for 2% and the rem

history as well as fracturing of sidetracks and fracturing of infill drilled wells are a common practice nowadays. The oilfields are typically dev 4. Recent efforts have been given to map out the pattern of induced fracture networks based on observed microseismic event distribution 13

to very poor reservoir characteristic this level was abandoned and the well was recompleted on the shallower reservoir B4. The low permea uctivity from horizontal wells that are completed open-hole. This opens up a window of hope for the dilemma of many horizontal wells that h wi Oolite section. The Ratawi Oolite in SF is characterized as a thick porous interval with good hydrocarbon saturation a clearly defined o nce and used for forecasting wells and field performance for our clients. Since completion of the integrated studies step-out and infill wells d during late Cretaceous through Tertiary time when the North Horn through Duchesne River Formations were deposited.� The basin is servoirs are poorly correlatable over a large area. The sandstones are fine- to medium-grained with porosity ranging from 5 to 14% and pe e completion engineer often uses to assess whether a zone should be attempted for stimulation is to perforate and flow the well. This luxury

and fluids and their heterogeneities. The most significantly innovative development of formation testing technologies is Downhole Fluid Ana ds in the world producing from Cambrian-age sandstone reservoirs with porosities ranging between 3 and 10 PU and matrix permeabilities t eservoirs mandates equally tight well spacing driven by reservoir connectivity permeability well costs and gas prices. Tight gas fields typica

ation without influence from the mud’s hydrostatic pressure. ����������������c.��� The southern area is waterflooded peripherally while the central area is line-drive oriented to avoid premature watering out of production we

massive deposit associated with a gigantic natural reservoir in the Riphean multiple-aged mostly dolomitic vugular-fractured reservoirs co

been reported that a reduction in oil wetness is accompanied by a reduction in irreducible oil saturation (under primary imbibition) and a co

gh’s in understanding of the reservoir complexities and behaviour and this has resulted into a more integrated approach to the manage

d predictable mental errors. In the case of oil and gas exploration and production such biases may possibly lead to very damaging mistake how we remember and recall certain information. An example is hindsight bias (“I knew it all along) which can affect judgment elicitation

ed and implemented. In addition many of these reservoirs exhibit variable initial saturations by virtue of being located at different heights (a servoir management. Core experiment open hole wireline logging wireline formation tester pressure build up injection/fall off test and pro be distinguished and this technique has been successfully applied to Gulf Carbonates3. This is of particular interest for carbonate as it is w water. The basin is divided into sub basins by fault-controlled ridges. Sediments accumulated in sub basins more than 5 km thick.

and optimization of production strategies. Formation-tester tools have proved to be an effective way to obtain reservoir-fluid samples for PVT y alter well productivity ultimate recovery and project economics. In aging reservoirs fluid movements are of constant focus and routine ca on would also help in designing a water injection program for such reservoirs. This study uses an integrated approach using the NMR and t were defined and the water saturation in the 3 dimensional spaces was modeled through saturation height function for each of the reservoir ma ray measurements is located only 5 ft above the bottom of the tool. The gamma ray detector uses a very large sodium iodide crystal to a and design proper field development scenarios. Porosity heterogeneities within complex carbonate sequences can cause the potential of a

and adds excess conductivity to the interstitial water conductivity so more than thirty shaly sand models have been developed in the literat onductivity to the interstitial water conductivity so more than thirty shaly sand models have been developed in the literature to get accurate w pported by the workflow presented in this paper and in addition to these methods there is potential to examine a new form of rock typing b t objectives of borehole imaging in the study well. Borehole images were used to identify open and closed fractures. Sand Count analysis p upon recognition of grain size trends bioturbation and surfaces in the core.� The transgressive system tracts are characterized by highly oil-base borehole images and nuclear magnetic resonance (NMR) logs as well as acquiring rotary and fullbore cores has increased over rec

w the thin beds workflow using both 3D NMR and 3D induction data. Combining the two dataset provides useful check points to ensure the b

ecline have been observed across the majority of both hydraulically fractured and conventional wells in Hassi Messaoud field. In the majori d sampling operations is essentially a two step process. The first step is to prevent solids mobilization or to limit the amount of production o ditions and offers quantitative information that is particularly useful for fracture analysis. The resulting data are valuable not only for geome n. In the exploration area to the north and northeast of the Al-Khafji field sinuous shaped channel features may be interpreted as possible s

stics has seen more extensive applications in the last half century (Matheron 1962 1965 Journel and Huijbregts 1978 Cressie 1991 Chiles Spectroscopy with formation density and resistivity to provide a rapid and robust evaluation of clay volume porosity hydrocarbon saturatio Core data in one well was used to validate NMR detection porosity permeability and net sand thickness. Introduction Thin beds evaluatio

low permeability reservoirs infill production wells or injection wells for improved oil recovery high pressure gradients can lead to significan

irs. Both the direction and magnitude of these stresses are required in (a) planning for borehole stability during directional drilling (b) hydra

h Eqs. 3 through 5 for time flow rate and wellbore pressure respectively.� In the case of an unfractured vertical well the system charact

cture therefore natural fractures will be prone to be discovered due to the peak of folding is considered as one of the highest strain point. T beria showed that production potential is mostly related to the basement limestones that have been significantly affected with secondary pro data. The majority of these faults are closed in nature. mostly related to the basement limestones that have been significantly affected with secondary processes such as dolomitization leaching

s. This usually results in longer cleanup times especially in tight formations. iii. Fines migration – another reason for near wellbore format

a). For e-log interpretation purposes we have classified lithology of the Devonian formations under three main petrofacies: a) quartzitic sand hydrocarbon type and properties logs. For example it is impossible to detect compositionally graded oils from Φ Sw and k logs and theref

eryday NMR was the use of T1 logging for porosity where the longest wait time used is approximately 1.5 times the longest desired T1 valu cations.

ays the case. By applying inverse modeling methods (assuming reasonably accurate data) it is now possible to determine reservoir param iod; small NS faults in the north EW trend en-echelon faults in the centre NW-SE faults with a large extension in the south-west part of the

e fluid property measurements. These include optical absorption spectroscopy optical reflectance fluorescence and a few other non-optica the methods available for downhole fluid sampling is via a wireline formation testing and sampling tool (WFT). With current technology it is with Eqs. 3 through 5 for time flow rate and wellbore pressure respectively. In the case of an unfractured vertical well the system characte mulation has confirmed that these tar-mats adversely affect vertical reservoir connectivity. The reservoir comprises clean fluvial reservoir sa ese challenges particularly near wellbore formation alteration have been studied using a multi-probe wireline formation tester (Ayan et al. 2

be calibrated by direct measurements. In this paper the first micro-fracturing operation conducted in western Siberia Russia using a WFT analyze data acquired with single or multiprobe formation testers. The software consists of a new mathematical model coupled with non-lin d not only include recommendations for an optimum development strategy with its implementation plan but the estimated risks involved in e ential item required in order to determine these key parameters. Moreover pressure data complemented with downhole fluid analysis and s llation in Malaysia The inception of this pilot project is considered an important milestone in PCSB’s effort to establish an alternative a nly from formations of Tertiary age lying at depths ranging from 500 ft to 7 000 ft. As of today there are in excess of 5 600 wells drilled in Blo e through 47 wells with 97 active production strings.� The field comprises multiple stacked reservoirs in unconsolidated sand. Gravel pac

the Grayburg and San Andres that produce from depths between 2 800 feet and 3 400 feet. CMC / IPM’s performance as the opera field which spans vertically about 5 500 ft with more than 165 individual reservoirs. Existing wellbore trajectories are shown as lines; oil-be ough has a different effect on individual well production depending on the fluids and well type. Highly deviated or horizontal wells experienc The field development currently consists of 96 wells (88 active 5 inactive and 3 abandoned wells) which produce from two separated reser ework in the following parts of the paper) enabling the management functionality required by most conventional fields. Extensibility and fle onitoring and surveillance activities take place based on high-frequency field data collected through SCADA systems. To achieve optimal op es is available on the platform. Major changes would have to be implemented prior to any secondary or tertiary recovery method and would al wells. The second campaign in 1988 drilled 10 additional wells and worked over two existing wells. The third revisit was in 1994 to sidetr

n a surface network which has to be balanced to account for varying fluid flow and pressure conditions in every well in the system. Their in However existing work flows and applications will have to change. The questions are by how much by when at what cost and with what tional teams to better analyze their assets to improve operations and optimize production. However proper workflows and technology must ses the most time consuming task in integrated study workflows.� It involves the calibration of the static model to dynamic data and it is t e to sand production so the typical completions are internal gravel packs inside a 95/8-in casing producing through SSDs into 27/8 in or 3

ng high water production from all of the existing wells. Due to reservoir heterogeneity some of the reservoirs exhibit uneven strength of aqu rik and Miqrat formations. Introduction Because much has been published on this field during its development in this paper we divert fro ction from multiple zones which complicates the production data analysis. Due to the low permeability the average reservoir pressure cann day. Such a valuation is intractable using existing deterministic or non-probabilistic numerical modeling schemes. We demonstrate the conc

asurements (a few feet) but this technology typically gives poor well placement results (see figure 1) especially in thin reservoir targets. A n ermine the potential of developing the Brenda field. An initial appraisal well drilled in 1990 by a major oil and gas company indicated a 22 ft t ies which collectively can have a pronounced impact on the efficiency of reservoir drainage and recovery.�Integration of these activities rom the Lower B4 reservoir horizon. The original mini-basin appears to have been uplifted by deeper salt intrusion leaving the present rese given the lower investment required? This uncertainty makes unlocking the potentials of a brown field is still a reinforcing process.� Wh o the reservoir simulation results. These were the basis for the subsurface team to determine the most suitable wellbore trajectories and co by Lui and Jalali (2006) where standard reservoir models are transformed to maps of production potential to screen regions that are most f

ate for slightly compressible fluid gives the diffusivity equation which is the equation for pressure diffusion in porous medium.� Solutio very fast model building and execution similar to a material balance or decline curve technique but which is based on solving the same set of data-independent prior information is generally added to the objective function in the inverse problem. Two different approaches to incorp e modeling process as the majority of the development plans should be based on examining it on the model before accepting it for practi

a measure of geological consistency which are insufficient to account for� strongly connected curvi-linear geological objects such as cha

and instantaneous phase equilibrium are valid. It is also assumed that the aqueous phase contains no components that partition into either ells which is referred to as the adaptive implicit method (AIM). The discretization used for flow and transport terms in the equations. For ex erforated interval produces. Practices have been reported to optimize horizontal well placement drilling completion and stimulation for prod

duces from multiple formations. However there are various factors that may cause part of the perforated interval to not contribute to produc

proppant pack significantly. As a result hydraulic fractures contain partially broken fracturing fluid and residues remain after the breaker re w days after stimulation and then experiences a rapid production decline. Some tight-gas wells in contrast do not show such obvious prod ents. A well in this reservoir was selected to be acid stimulated using a multi-stage open hole completion system with isolation mechanical ent approaches are being used for gas condensate flow to fractured wells. The most popular of them is based on the multicomponent flow s n the effective normal stress across the interface is low. For horizontal bedding planes the normal stress is the vertical overburden stress. In ftware such as nodal analysis software with fracture modeling capabilities or to use specialized hydraulic fracture analytical simulators. Th

pled with a non-linear regression algorithm (Levenberg-Marquardt algorithm) to find values of the individual layer properties that give the be expressed in terms of the pressure drawdown of the system between the initial pore pressure and the sandface flowing pressure (Pi-Pwf) fi the net pressure was high and almost stable throughout the pad stage instead of being high and increasing (PKN) or low and decreasing mate conditions resulting in different scenarios of fracture initiation and identify factors affecting initiation and growth for a given scenario. M es prediction (Sultan and Al-Kaabi 2002) and well-test-data analysis (Osman and Al-Marhoun 2005). Given a basic network structure there

king low angle dip-slip fault that was active since Early Pliocene up to Pleistocene. It dies on the top of the Messinian rocks and divided the .g. currently of the order of 1 to 2 km). “Interventionless means of determining the i

at oil and gas production are measured with confidence since industry revenues are based on oil and gas sales and consequently error in p

2006). The combined effect of convection and diffusion on species separation has been the subject of many experimental studies. Separati points in their project maturity spectrum. Though this paper does not purport to have all the answers it attempts to address the painful challe

een neighboring control volumes and relate the flux across the boundary with pressures in the control volumes. Here we apply multipoint tra

em. This work concerns isolated vugs. The definition of “isolated vugs used in this paper considers vugs that do not have a connection structural deformation accompanied with fault slip. Recently an application of the elastic stress simulation has been proposed for predicting

as to satisfy CFL condition for the explicit case. The convergence of the non-linear equations for the implicit approach may also require sho provement of the computational efficiency of the streamline simulator has been pointed out in [16]. It is well known that an explicit numerical on methods based upon dual-porosity descriptions may not be able to deliver sufficient resolution of the complex flow patterns that may dev

arker et al. 2001). The problem was set up as a test case to allow various research groups to test their own methodology for the characteriz

barium ions then barium sulphate may precipitate in the formation and/or the production wells. Understanding where and when the scale fo

ns are transformed into a set of 1D equations along streamlines. Note that there are two time scales in the streamline simulation process: t processes during the calculation step and may use a relatively large share of total CPU time consumption. In this paper we propose a spec arguments to formulate an innovative strategy to accelerate the exploitation of oil and gas assets of YPF in the San Jorge Basin Argentina.

means of a mathematical tool called Principal Component Analysis (PCA). Down hole monitoring system yields continuous pressure data o uch that there was only one flowpath from each section of the annulus into the well tubing (Fig. 1a). This restriction limited the usefulness o

available fluid sample analysis from 3 wells in Najmah/Sargelu and 8 wells in Marrat it is assumed that all regions contain gas-condensate (

eimer equation. In the discussion of Batenburg and Milton-Tayler1 and Barree and Conway 2 it was presumed that non-Darcy flow in their e elow the oil zone the location where oil ceases to be mobile) SWI (as depth increases below the oil zone the location where water becom ma Limestone group is highly fractured with the troublesome overlying Nahr Umr shale cap rock which has caused drilling problems in the p n of the area. This is a significant and most important input to forecast the drillability of the well. And in most of the cases the wells are bein development and deployment of these technologies has normally been in Partnership between a major operator and one or more key sup

eater or lesser degree. The ANS extends from the Canadian border on the east and into the Chukchi Sea on the west. The ANS includes t of the cement sheath to strain is determined by the static Young’s modulus and Poisson’s ratio of the cement through Hooke’s

potential of the through-casing resistivity measurement compared to its nuclear counterpart since its deep depth of investigation gives mor plemented on the Troll and Vestflanken subsea fields. There was a growing understanding that downhole production monitoring was neede the Mauddud Formation. The focus in this article is the production logging applications in the Sabriyah Field. The following part summarize Production log interpretation in horizontal wells is complicated particularly with two-phase (gas-oil) flow down-hole as in Chayvo.� Interp

n pressure. We therefore have to design our sample acquisition program with the following considerations: �������� ï¿

will usually provide good-quality water samples because the mud filtrate is not miscible with water. Water-based-mud filtrate can contaminat smart well data develops a new integrated workflow that enhances more than one discipline. One such example is the collection of pressur al. 2005). We have analyzed one hydraulic fracture treatment that was carried out in a nearly vertical borehole at depth intervals between 4 servoirs specifically the Quartzite of Hamra. However due to the tectonic history of North Africa hydraulic fracture design execution and e

pair of wells in Phase I a fiber optic distributed temperature system (DTS) was installed in the producer well and the data from this was mon ½ï¿½ These are the criteria for moving the liquid film along the wall of the conduit upward as well as the criteria for suspending and transp oving the liquid film along the wall of the conduit upward as well as the criteria for suspending and transporting entrained liquid droplets in th ects. The introduction of permanently installed fiber optic distributed temperature measurements (DTS) in the late 1990’s revived the in

ator method.

plicated as it needs further investigation test and analysis by the production engineer. However independently of the result of the analysis nsitive to one of the phases another is multiple phase-sensitive sensors; each with a high geometric precision and a geometric arrangemen a have been acquired at some wells completed in Wara on a non-routine basis. is destabilized which is caused by the changes in temperature and/or pressure during primary depletion.2 On the other hand asphaltenes ENERAL INFORMATION NR field was discovered in August 2002 in the Western Desert of Egypt (fig-1). This field is producing from the Al he hydrocarbon fluids and water in terms of chemical and physical properties phase behavior and commingling tendencies. Cased-hole su o needs to be flowed at a reduced rate. There is now a third alternative that does not require shutting in the well or reducing flow rate and tion. In some fields this geomechanical deformation also leads to casing deformations and well-integrity problems which may result in ope place. The field’s north flank dips steeply at about 35 degrees and has a 1000-m oil column between the gas/oil and water/oil contacts. d multistage completions. Despite the growth in the number of wells the expense of subsea well intervention often leads to insufficient rese

etect any production measurement errors lost production production well test validation etc. to have reliable data for reservoir modeling a spinner and probe sensors are not uncommon. Producing horizontal wells completed in unconsolidated and poorly sorted formation sands

f fluid movement etc. depends primarily on the saturation estimation at different stages of the life of a reservoir. Time lapse monitoring of a

erial that would limit the attenuation at high frequency as much as possible at source and receiver locations. Introduction Peripheral water l is to design an optimum field development scheme for the lower reservoir units in the southern part of the field (Bhatti et al. 2007). Assess orated multizone completions rather than open-hole completions in a single interval. In Canada the Horseshoe Canyon coal is expected to ace and butt cleat permeability anisotropy is prevalent in coal seams ((McCulloh et al. 1974 Mavor at al. 1991 ). Figure 1 displays a schem ed by invasion damage from the drilling fluid completion cement or a mechanical skin caused by hoop stresses around open hole completi ts consisting of crosslinked gelled fluids and large amounts of proppant. Because of difficulties with effectively cleaning up fracture damage fluids may then be used to facilitate fracture initiation and promore less tortuous (i.e. wider) fractures near the wellbore (along with sand slu

ment with Slickwater stimulation treatments.� These treatments contained roughly twice the fluid volume of the large crosslinked treatmen umber of horizontal wells have been drilled and massive multistage HFT jobs have been performed. Due to the complex nature of the Barne egies on oil production and SOR in the Athabasca Oil Sands. Advances in technology and computing power now make simulation of a SAG actures are healed by a mineral filling and must be forced open by hydraulic-fracture stimulation. It also is possible to have both shales and fashion as for re-fracture stimulation applications. Introduction The Barnett Shale is a Mississippian-age marine shelf deposit that unconfo ered by the acidizing process. Since the matrix structure is generally intact the entire physical and chemical processes can be modeled by b

or which produces power. This power is used to operate the inlet air compressor. Thus the cycle is completed. Thus this system achieves w cks of continental and shallow-water marine origin. The productive reservoirs formed in different facial settings. Genetically three types of s

ideal since layers with lower fracture gradients or formation pressure may take more of the treatment than planned leaving the higher pres n the field. The skin estimation based on the model compared very well to the measured values during production tests. experiments have clearly demonstrated that only slight changes in the inclination of the wellbore can have a dramatic effect on the types o experiments have clearly demonstrated that only slight changes in the inclination of the wellbore can have a dramatic effect on the types o y was interpreted to be low and therefore matrix permeability was presumed to control the fluid flow.� This paper describes the process

uction was suggested by Rinaldi (1987). Recent papers [for an example see Graf et al (2006)] address optimization of intelligent completion

lled with a conventional completion configuration. Acids can attack both metal and elastomeric materials used in ESP systems. œsystem and “components. We then present a summary of the extensive data set employed in the analysis. The remainder of the pape

fluid systems were reviewed and a borate cross-linked low polymer loading system was selected based on the high retained permeability r

th porosity development of 5 to 14 percent with an average of about 8.5 percent in this area.� It has oil saturations of 60 to 90 percent de polymer concentration non-crosslinked fracturing fluids regularly in order of 1.7-3.0 kg/m3 (15-25 lbs/1000gal). Fiber addition improves the

es being realized as application expands to new areas.� Since 2000 fiber-laden slurries2 have been used to improve fracture geometry plicated in their wettability. Almost never are formations pure sandstone. Clays line the pores of most reservoir rock and in the case of shale ore contained in height than predicted by simulators. Some new mechanisms and explanations have been given including the “compos of associated equipment is always a major consideration and processes that would minimize time spent are generally welcomed. To this en n effort to circumvent some of the extra costs operators have reported the use of recycled produced waters in reservoir management proce ses on three major formations (Figure 2): Upper Williams Fork (Porosity (favg) = 7.8% Water Saturation (Sw) = 48% Avg Net = 110 ft) Midd ough the gravel remaining in the casing and additional sand was placed around the screen. Frac-and-pack became a premier completion te e of the premature treatment termination will ultimately also have an impact on the frac productivity. For that purpose many operating and s d for not saying abandoned. In 2006 Kuwait Oil Company (KOC) contracted the service company to revisit this problem and determine if th ve the same sub hydrostatic pressure. The reservoir gross heights range from 80 m to 500 m. The composition of the matrix is mainly sand nd better access to reserves. Often times fewer horizontals are required to develop a field given its larger drainage area. However horizonta

ure intervals and intervals that fracture early will receive more than the designed amount of the stimulation treatment. The remaining inter d case when TSO occurs too late the remaining volume of slurry is insufficient to produce the desired fracture width. Both cases produce su scosity even in dry gas wells where there is neither brine nor liquid hydrocarbon to assist the breaking process.� The effectiveness of thi

have different trends and detrital and authigenic compositions.� Simply stated a large variation in geologic and petrophysical properties o

production. Improved oil production is required for Marrat wells to increase production and maintain the flowing bottomhole pressure above until the first publication9 resulting from this JIP work was made at the Formation Damage Symposium in Lafayette February 2006. In a se nment.2� The thickness of the Cotton Valley sand can grow as large as 1 500 ft.1� Changes in stream positions and shorelines due to

ositions. Fracture geometry (mainly its azimuth and length) resulting from such HFM is then used for “infill drilling during which new well

may depend more on rock strength than on the initial etching pattern. In this paper we present an experimental methodology to characteriz Western Siberia. The reservoirs under production are part of Cherkashinskaia set of rock [1 2] composed of shales siltstones and sandston t didnot give the desired information on the location of the proppant that had been pumped. In more recent times the use of radioactive tra

osition and production prediction that have been historically applied in the field had to be compared to understand the possible discrepanc ermeability will vary with distance from the wellbore increasing towards the tip of the fracture where both the liquid-to-gas ratio and the ve

ight gas reservoir which has a porosity ranging from 1 to 25 vol% in the higher porosity sections. These types of porosities coupled with th

sampling of the radiation pattern certainly limits the uniqueness of the fracture-mechanism analysis. However in some projects in which mu

ts et al.3 further extended this work by studying the stress distribution around a producing fracture using a 3D numerical simulator and inve rely heavily on the elastic (or poroelastic) representation for the porous skeleton. The present paper provides the data on hydraulic fracture using sizes as large as 10/14 mesh. This increases the risk of treatment failure (screen-out) that is caused by modeling discrepances/inaccu

nt (FIG) or yield stress effect. A modified conductivity cell was used to allow a series of measurements aimed at clarifying the polymer conc njection was required from day one for pressure maintenance purpose to support producing wells at both the Spar and subsea. Kikeh is pla borders and specially a massive campaign of hydraulic fracturing in all producing wells resulted not only on the attenuation but also on the path. Later studies were concerned with details of the interaction between a hydraulic fracture and a natural fracture and studied conditions arious papers have discussed applications of this technology (Betancourt et al. 2002; Al Kasim et al. 2002; Clarke et al. 2006) but so far no measured depth of 12 290-13 566-ft (9 834-10 292-ft TVD) with 9-5/8-inch casing set at 14 350-ft. The reservoir section was drilled with a reservoir is not a challenge anymore. While horizontal drilling has progressed over the last decade to become the field development method eservoir is not a challenge anymore. While horizontal drilling has progressed over the last decade to become the field development method erized by its low permeability. Its productivity while produced through vertical wells is low and deemed not satisfactory. For this reason deve lts. These faults and fractures have been identified from openhole logs and are most prevalent in the northern part of the reservoir(Ref. SPE 5 Ecuador�� and its application will be considered in other fields. Introduction Bloque 15 is located in the Oriente Basin Amazon jun

isms are well understood so that inflow can be predicted with confidence using reservoir and well models and if the predicted inflow does n between fractures generated in laboratory tests and in field applications. To account for these scaling issues model laws that relate experim

curate reservoir pay thickness (Ref. 1). In addition to these new logging techniques interpretation methods such as Log Enhanced Resoluti Reservoirs with rock strength from moderate to intermediate will benefit most from a sanding prediction study. The completion and operation genic processes through the geological time.� It is the nature of the carbonate rocks.� But near a wellbore heterogeneity can be furth heast direction. The petrophysical characteristics of the Tadrart sandstone are good with porosity ranging between 12 to 16%; the permeab ucer well was drilled in March 2004 and completed in 4-1/2 monobore completion by penetrating the reservoir of� J-10.2 & J-10.1 with Js an area that could be improved in Anaco District well completions. As a result a qualitative evaluation of conventional perforating perform ting-induced damage. Permeability lost through formation damage could be regained through stimulation treatments or by completing the z the tradeoffs between different perforating parameters for non-oriented perforating; oriented perforating avoids many of these tradeoffs. Be al runs of perforating on wireline to complete. Using the equations for underbalance determination3 the optimal static underbalance to clean w rate is maintained in a constant or switched among two or more constant values. Almost all analytical solutions developed for PTT interpr act on cost deliverability include Perforating off depth due to inaccurate depth control Guns not fired due to pressure discrepancies disc n swell can help risk management in at least two respects. First analytical tools such as swell modeling can serve as a supplemental measu

e geological complexity (resulting from a complex turbidity depositional system mainly represented by channels lobes and overbank facies

been a challenging task from both technical and economic perspective since the number of open hole completions have increased significa l sorted with low to high fines content. This particle size distribution data (PSD) combined with the limited amount of whole core data availab

hout affecting the well performance the gravel packing using 40-60 US-Mesh has been considered mandatory as well as the isolation of th window between downhole circulation pressure and the fracturing pressure is narrow. Various hardware and chemistry solutions exist to ov

rate of penetration excellent shale inhibition characteristics gauge hole lubrication while drilling as well as while installing sandface com tion of sand is a worldwide problem. Areas of major problems include the U.S. Gulf Coast Trinidad the North Sea Venezuela Brazil Mala roduction of sand is a worldwide problem. Areas of major problems include the U.S. Gulf Coast Trinidad the North Sea Venezuela Brazil d production. For the long horizontal oil wells that are due to be drilled sub parallel to the dip direction and that will penetrate several sand f he producer to the injector. This characterized by large volumes of sand matrix and fine clay particles being produced where water breakthr (HRWP) and Gravel-pack1-3. Each of these options involves downhole hardware that is primarily conveyed by a rig. However there are ins

problems. AGOCO the field operator investigated the issue and in 1992 the first gravel-pack completion was installed in the Well A to prev e results that closely matched field experience but was also able to predict correctly to the year the onset of sanding in wells. This paper d months. Sanding in the cased and perforated well AA05 had been reported that since 1970 it got fill of 882 ft in four months and up to 906 d that sand-production risk increases as a result of water production.

ydrocarbon production from clastic reservoir rocks. Over the last decades a lot of research by service as well as production companies has ones and shales were established by conducting a number of unconfined compressive strength and triaxial tests on reservoir cores. The lab and surfactant-based. Acid-soluble polymers have been used to increase the viscosity of HCl and to improve its performance (Pabley et a and the closure stress. At low closure stress the etched pattern of the fracture face should have a dominant influence on the resulting fractu a well’s life from drilling to completion. New technologies and methods have greatly enhanced production by offering data and solution

d great success in vertical gas producers in which post-stimulation multiple-fold rate increases have been consistently realized. More recen ds used previously. Discussion Before December 2003 the predominant procedure for stimulating wells in Tengiz was the use of 15% H placement strategy such as formations with low mechanical integrity and with highly viscous formation fluids. Carbonate reservoirs are sti

mage materials in the near wellbore matrix. In addition reaction products due to the reactions of the stimulation fluids with various mills and

e wells. Organic acids have been used in well stimulation because of their low corrosivity4 and lower reaction rate with the rock. �Howev

wever the physics and engineering aspects of the carbonate acidizing process is much more complex.1� This is because the rock structu aulic fracturing mainly in mid-temperature deep Neocomian and the overpressured high-temperature (above 100�C) �deeper Achimov ids under varying conditions of injection rate temperature and concentrations have been reported in the literature 1 2.� However few stu ingredients for the success of restimulation and (ii) a thorough understanding of the treatment parameters that govern the success of a rest it was decided to fracture stimulate only the first Frontier formation and as a result of the stimulation the well is producing on average 1 10

ths of 2179–2320 m and Triassic horizons at 3109–3308 m.

All stimulation treatments were performed in Triassic formation. The heig

pproach will not only involve the workover rig but also impact the production from the lower Burgan sandstone formation as well as formatio d the rig has left location. Because of the importance and criticality of the zonal isolation between oil bearing formations for reservoir manage ses the chance of capturing the data dominated by the reservoir-dominated flow. A typical DST chart is presented in Fig. 2 highlighting the es and determine to which extent they enhance the well productivity. A pressure transient test program was carried out to establish the pote ptimum completion design and operating condition well/reservoir production option used will commonly be the optimum solution indicated on

ical equations to determine reservoir and well characteristics without using type-curve matching. These characteristics are obtained from un s of investigation first we look at the pressure distributions in a 1D radial-cylindrical homogeneous reservoir produced by a fully completed tives of every operating company is to optimize reserves in order to maximize their assets value.� For the reservoir engineers in the brow bjective of applying pressure/rate deconvolution is to convert the pressure data response from a variable-rate test or production sequence in

ate methods of interpretation require well tests of quite long durations (Horne and Kuchuk 1988). Kabir (2006) suggested a two step appro een deployed throughout its development to curb the decline in production and extend its life such as phased development secondary rese separator Increasing need for high resolution of GCR measurements to determine changes in fluid properties on choke changes Higher re

application and performance of multiphase meters has been well documented through technical papers and industry forums and after sev ormed by the existing test separators in ADCO fields was an issue rose long time ago. Field reports always indicated that the actual produc

measurement. The fraction measurement techniques are more versatile and we could split them between low energy gamma ray measurem ation models particularly for permeability. This is because of limited core sampling from the reservoir and difference in scale between grid b

the point of interest.11 Regardless of which method of numerical differentiation is used and regardless of the manipulations employed to re that was drilled in a thin oil column within a Cypress formation sandstone reservoir. 3 4 The well was completed openhole with sand screen

resistance to CO2 aggression and more frequent defects related to slurry settling. Defects such as liquid channels in cement can even pro ell(s) and the storage capacity of a repository. Insofar as the stability of faults or the compressive strength of rocks generally depend on all

available through several commercial or pilot projects. Geological storage injects CO2 into either oil or gas reservoirs aquifers or coal beds. oving water from the brine and increasing its salinity as salt concentration increases leading to dry-out and salting-out. In this article we f

ns from anthropogenic sources have also been increasing in the same time frame and these are known to produce a greenhouse effect. . As evidenced by oil gas and even CO2 natural accumulations rock formations can be impervious enough to act as flow barriers over geo

es. This is the longest DIACS completion in the world with the lower isolation packer set at 8560 m. The well is produced at a rate of 2500 or then decided to abandon any further development enhancements and to continue producing the existing wells until it ceased to be profita

mechanisms in the Southern Michigan Basin Reef Trend. In 1969 the first field in the Northern Silurian Reef Trend was discovered leading g >1% concentrations of CO2 in a gas reservoirs is < 1 in 10 and the risk of encountering >20% concentrations of CO2 is < 1 in 100.� Ho uth Texas partners make their decisions based on these cutoffs and individual experience. Worthington gives a comprehensive perspective tailed reservoir simulation study with proper geological description and project economic analysis should be conducted to guide the succe

n fractured broken and catalazited at various degrees developing different fracturing systems with different directions. The fracturing and b p and bottom perforated zones in order to provide both proper zonal isolation and accurate treatment placement. TTIP Technology Overvie n successfully carried out on wells with single-string multizone completions. Introduction Cement-water shutoff intervention behind the slee The main production challenges in south Boscan wells are; 1) Surface facility limitations in handling produced water; therefore the volume

dy based on asphaltene precipitation experimental information published in the literature1. Experimental data included evaluation of propen holdup profiles and pressure gradients. These internal-flow structures depend on variables such as flow rates of both liquids pipe geome ed. The water holdups and pressure gradients are measured and analyzed. A simple two-fluid oil/water pipe flow model was proposed by Z al rate in the moment first signs of breakthrough appear. Commingled production from two or more productive horizons is the ideal metho per workflows and technology must be set in place to allow different domain engineers share ideas properly and lead into proper integrated nes by commingling streams from several wells can reduce capital and operational expenditure but may cause problems if the fluids in the s equired to “tune theoretical models. In addition to quality and accuracy if flow assurance properties are measured at the representative il industry picks up more than its fair share. The combination of water and carbon dioxide naturally produced or injected for secondary/tertia contamination2 to measure Gas-Oil-Ratio (GOR) and Condensate-Gas-Ratio (CGR) to provide fluid composition i.e. C1 C2-C5 C6+

sate samples. This is the first proposal offered in petroleum literature of a correlation to estimate the decreases in surface yield. o referred to as rs2).� This function is similar to the solution gas-oil ratio Rs normally used to describe the amount of gas-in-solution in t erformed by specific tools such as the LFA (Live Fluid Analyzer) which performs spectral analysis of crude oils downhole immediately after re nd routine cased hole logs are common to track such changes. Location of news wells for bypassed/remaining oil is equally important. In ce n that a single pressure gradient identifies a single flow unit can be in gross error [3]. It often indulges accustomed or habituated practices to

e of hydrocarbon fluids in terms of chemical and physical properties phase behavior spatial distribution and hydraulic and thermodynamic

n be challenging for contamination quantification during sampling operation it has been shown that optical spectroscopy can be quite effec The accurate measurement of H2S concentration in the reservoir fluid can often be critical to completion surface production and process d

nant role in distributing hydrocarbon components in the fluid columns studied. ble point of oil in a trap reflect the pressure and temperature history of the trap (Stainforth 2004). Compositional grading can be caused by

sured in separate sample bottles might be caused by differing levels of oil-based-mud (OBM)-filtrate contamination or to some degree of no bility effects and depth measurement errors can make it difficult to acquire representative pressure data and hence limit fluid gradient accu and deep offshore settings more and more fluids with complex phase behavior are met. Crossing the phase envelope of a hydrocarbon fluid to 15% for crude oils or 1 to 3% for gas condensates). In-situ sample OBM contamination can be predicted in real time by a downhole optic

uid gradients. Introduction Compositional variations in reservoir fluids with depth are more common than perhaps normally expected and ha density hydrocarbons which have a larger concentration of aromatic molecules have a tan brown or black color while low-density hydroca The sampling program can be optimized during the job and the operator can decide when where and how many samples to collect. The

½ If heat continues to be added to the system all volatile liquid components will eventually vaporize.� If some components in the system acids also enhance the stability of emulsions (Kokal 2005). Because of the presence of these elements the occurrence of tight emulsions in

measurements. The presence of compositional gradients because of fluid migrations or fluids showing near-critical behavior at reservoir tem etermination of the drawdown threshold and controlling the pumping rate ensured that liquid drop-out did not occur in the flowline during the upper limit can be extended to 5000 psia with great care (Ref [2] [3] [6]).1 using experimental and modelled data from an Equation of Sta ll be presented in a separate article. Introduction Comprehensive understanding of the drainage behavior of gas condensate reservoirs in ogler 1998; Huang et al. 2000; Nasr-El-Din et al. 2001). These acids are weakly ionized and slow reacting. Acetic and formic acids are less as been revealed on lab analyses. Second when damage has impact on the injection trend it is important to execute a matrix stimulation tr enerally acid-insoluble (being largely composed of an insoluble quartz matrix) and therefore matrix acidizing intends to dissolve the damagi due to the very large volume required during wash treatments. These issues necessitate preventative measures through chemicals with hal

18-in. length samples under downhole conditions and with the full analysis and control of wellbore dynamics. In a perforation flow experime of undamaged rock; for gas-saturated rocks the porosity of the damaged zone may be much reduced.�In the damaged zone the pores he most common scale deposits found in operator’s oilfields is calcium carbonate scale (CaCO3). The uniformity of the finding is obviou ufficient protection time. The efficiency of a scale treatment can be estimated by the scale inhibitor return profile. When the inhibitor concen

and solve all the problems related to lack of integrity in each well. Scale management system is a major part of ZADCO WIMS. In 2001 ZA ld lead to a severe scaling tendency[1].�The current operator Talisman have sought to review the scale management process to ensu on three case studies. Description of the Method Sensitivity analysis is performed at certain pre-selected pilot-points (or the grid blocks). Du

ry few hours (sometimes minutes)2.� Such rapid turn-around times have enabled the performance of numerous strategic analyses on ca Cantarell Field that will be discussed in this paper. omatic engineering workflows remains challenging given the lack of high frequency production data or connectivity. This paper demonstrate . The pilot will also address the issues of uneven sweep bypassed oil and residual oil saturation. The acquired field data will be used to cal

of 2 000 BOPD per well compared to the former 200 BOPD per well. Wells with productivity potentials greater than 1 000 BOPD are typica

ergy such as carbon (El Harfi et al 2000; Abernethy 1976) or certain metal oxides (Monsef-Mirzai et al 1992; 1995).� Microwave heating

ds from the Benue Trough in Nigeria to Cameron Chad Central African Republic and Sudan. The evidence for further southeast extension ounds and exposure surfaces. The average porosity is 35% and the average permeability is 250 md over the gross interval. Well log and co the Eastern European (Russian) and Siberian platforms where at least 700 billion bbl is present. Heavy oil and natural bitumen reserves an

ree are placed in Bentiu fiormation. The production performances of all the wells are extremely good year to date. Geological Setting and S

be cold produced because of its high fractures and fissures density. Producing the Nukhul heavy oil through downhole pumps requires 20%

clude 6:1.5 and 12:3 mud acid systems. The use of 9:1 or even 13.5:1:5 mud acid systems has been advocated to allow greater dissolution

t to be responsible for these observed gradings.1 3-9 The approach taken by most of these papers are to compare sector/field data with eq

d without permanent damage to the polymer molecular weight and therefore to the fluid viscosity. Low initial viscosity from crosslinking too

y target is the lower Miocene and Oligocene which are interbedded sandstones saturated with oil. Some of the wells show initial production a novel chemistry include simplified placement process (i.e. single stage) less precipitation tendency reduced tubular and production e pecially at temperatures > 150�F or in the presence of acid-sensitive clay. Acid treatment of sandstone at high temperatures therefore re rcial production levels. A typical San Jorge Gulf Basin well has an interval of interest located between 800 to 1200 meters with dozens of s mporary as the well has to be retreated with solvents if a water block problem reoccurs. Evaporation of water in the formation can also dec of organic compounds and heavy metals in water is performed. Dissolved organic acids also affect water chemistry because they can influe

shale accounted for 2% and the remaining 8% was coalbed methane (CBM). They projected that in 2010 the portion of gas that was tight ga

adays. The oilfields are typically developed with an inverse nine or seven spot pattern and are under intensive pressure maintenance progra ed microseismic event distribution 13 15. These interpretations were not closely constrained by accounting for the amount of pumped fluid a

lower reservoir B4. The low permeability reservoir D (less than 10 md) was therefore abandoned and only the reservoir B4 and B7 put on p mma of many horizontal wells that have already been drilled but perform poorly. arbon saturation a clearly defined oil-water-contact with abnormally low permeability. Low production rates from past vertical and slant-hole ted studies step-out and infill wells have been drilled and cores logs completion pressure and production have been collected from them. ns were deposited.� The basin is bounded on the north by the Laramide east-trending Uinta uplift and the Uinta Basin boundary fault on rosity ranging from 5 to 14% and permeabilities in the range of 0.001 to 0.03 md. Water saturation varies from approximately 30% updip to rforate and flow the well. This luxury does not exist for the tight marginal gas sands discussed here. The risk associated with stimulating a n

technologies is Downhole Fluid Analysis (DFA) which is rapidly advancing and the list of its measurements is expanding commensurately. N nd 10 PU and matrix permeabilities typically less than 10md. The field currently produces approximately 400 000 BOP from more than 700 p nd gas prices. Tight gas fields typically go through multiple rounds of downspacing dependent upon development pace well performance m

������c.���� All internal valves in the tool are closed creating a fixed flowline volume sealed at near hydrostatic mature watering out of production wells. A commingled production completion of the three reservoirs was selected in the central area becaus

mitic vugular-fractured reservoirs covered by Vendian-Lower Paleozoic cap saliferous in the Cambrian interval. The discovery of the accum

(under primary imbibition) and a commensurate increase in the relative permeability of the oil. But when one drills a well with Water-Base

integrated approach to the management of the existing hydrocarbon resources and producing assets. Continual advancement/improvemen

sibly lead to very damaging mistakes. which can affect judgment elicitation.

being located at different heights (above free water level) in the capillary pressure transition zone. Rock types are geological entities usua uild up injection/fall off test and production logging are the conventional methods for characterization of reservoir heterogeneity. Although a cular interest for carbonate as it is well recognized that unlike conventional siliciclastic reservoir carbonates have complex pore system distr sins more than 5 km thick.

btain reservoir-fluid samples for PVT analysis. Conventional reservoir-fluid analysis is conducted in a PVT laboratory and it usually takes a are of constant focus and routine cased hole logs are common to track such changes.� Location of news wells for bypassed/remaining o ated approach using the NMR and the micro-resistivity bore hole images for identifying and quantifying the secondary porosity and their imp ght function for each of the reservoir rock types which were later used for HCIIP calculations. As a result of this study the geo-cellular mode very large sodium iodide crystal to achieve high count rates and owing to a focused design the measurement has good azimuthal sensitiv quences can cause the potential of a reservoir to be inaccurately evaluated when only conventional approaches such as density neutron a

s have been developed in the literature to get accurate water saturations taking into account the excess conductivity due to shale.2 3 4 Th ped in the literature to get accurate water saturations taking into account the excess conductivity due to shale.2 3 4 The dependency of th examine a new form of rock typing based on estimates of relative permeability. Carbonate Analysis Workflow The workflow presented has t ed fractures. Sand Count analysis performed using the high-resolution azimuthal data from the borehole image was successful in identifyin em tracts are characterized by highly burrowed packstones and/or wackestones (typical burrower is thalassinoides) capped by a dense bor ullbore cores has increased over recent years. New logging techniques and interpretation methods have been applied to improve the evalua

s useful check points to ensure the best possible interpretation in thin sand/shale formations. A quick review of 3D induction technique is di

Hassi Messaoud field. In the majority of the transient test data performed in horizontal wells the analysis of the pressure derivative reveals or to limit the amount of production of solids and grains. The second step in this approach is to manage the produced solids and sand grains data are valuable not only for geomechanics but for reservoir characterization and fracture network evaluation. Borehole images and match res may be interpreted as possible strati-structural traps at the top of Tayarat Formation. Good porosity is reported at the top of this formatio

uijbregts 1978 Cressie 1991 Chiles and Delfiner 1999). Geostatistics as a major branch of spatial statistics is commonly used to model g ume porosity hydrocarbon saturation and permeability. Produced and delivered on an interactive PC platform this evaluation was complem ss. Introduction Thin beds evaluation problems with well logs have long been recognized studied and solutions proposed since the late 19

sure gradients can lead to significant stress reorientation in the reservoir. In this paper we study stress reorientation around a single produc

y during directional drilling (b) hydraulic fracturing for enhanced production and (c) selective perforation for prevention of sanding during pr

red vertical well the system characteristic length (Lc) is equal to the wellbore radius (rw).

as one of the highest strain point. The combination of formation micro imager Stoneley waves measurement elemental spectral device an nificantly affected with secondary processes such as dolomitization leaching and fracturing4. Following the initial discovery 19 wells have

es such as dolomitization leaching and fracturing3. Following the initial discovery 19 wells have been drilled in the Maloichskoe field and

ther reason for near wellbore formation alteration could be wettability change due to OBM invasion.� Such drilling fluids usually have sur

e main petrofacies: a) quartzitic sandstones b) micaceous and laminated sandstones and c) shaly intervals. Sandstones composition is rath ls from Φ Sw and k logs and therefore insufficient sampling might result. On the other hand excessive pretests and rig time might have be

.5 times the longest desired T1 value rather than the industry standard requirement of 3 times the longest desired T1. A specific example in

ssible to determine reservoir parameters such as permeability and pore pressure by extracting the productivity signature of the reservoir fr xtension in the south-west part of the field during the Ahmadi-Tayarat period. Most of the faults were generated during the Mutriba-Tayarat p

escence and a few other non-optical measurements. The spectroscopic DFA technique utilizes optical absorption properties of reservoir flui (WFT). With current technology it is possible to obtain contamination-free samples in a very short time.5 Furthermore this technique enable ed vertical well the system characteristic length (Lc) is equal to the wellbore radius (rw). comprises clean fluvial reservoir sands with over 1000ft thickness in places. Porosity ranges from 10% to 14% while permeability ranges u reline formation tester (Ayan et al. 2007). In this study the authors used dipole radial profiling and Interval Pressure Transient Tests (IPTT)

estern Siberia Russia using a WFT is described. The survey was conducted under heavy winter conditions which required special precautio ematical model coupled with non-linear regression methods for solving the inverse problem. It is possible to match the pressure transient d but the estimated risks involved in executing the proposed plan. So the ideal plan would have two parts: optimization and risk assessment ed with downhole fluid analysis and sampling may significantly improve the definition of fluid type and predict fluid behavior. At the top level ™s effort to establish an alternative artificial lift system for offshore production operations. n excess of 5 600 wells drilled in Block 10 and the current production is about 12 500 bopd. Perez Companc S.A. a company that was later in unconsolidated sand. Gravel pack is used as sand control method.� The oil is under saturated with 19-20 API in shallow reservoir and

PM’s performance as the operator has been excellent as illustrated by the project’s exploration exploitation production safety and ajectories are shown as lines; oil-bearing zones are green; gas-bearing zones red; and parts of the encroaching aquifer and the connate w eviated or horizontal wells experience a reduction of the effective producing length as gas and/or water reaches the horizontal section (Figur h produce from two separated reservoirs: B-1 and B-4.� B1 sand is under initial conditions with a 3500 STB/d as estimated potential wh ventional fields. Extensibility and flexibility of FM also allows workflows and logic that are difficult/impossible to implement within the prescri ADA systems. To achieve optimal operations efficiency adjustments may be made in existing field equipment. Example control devices inclu tertiary recovery method and would require economic justification. In addition existing fluid export constraints arising mainly from the curre he third revisit was in 1994 to sidetrack 4 wells. There are eight reservoirs that have been targeted and produced. All of the wells are dual s

in every well in the system. Their interaction will ultimativley lead to a newly calculated backpressure of the production system for every we when at what cost and with what benefit?�Multiple vendors must collaborate to create cross-discipline compatibility and Oil & Gas com per workflows and technology must be set in place to allow different domain engineers share ideas properly and lead into proper integrated tic model to dynamic data and it is the final process in reducing the error and uncertainty in the interpretation and analysis to acceptable lev cing through SSDs into 27/8 in or 3 1/2-in tubing. The deeper more consolidated formations do not require sand control and are completed

rvoirs exhibit uneven strength of aquifer support causing OWCs to tilt after years of production. To reduce and reverse the rapidly declining elopment in this paper we divert from the strict subject line of hydraulic fracture design (i.e. the type and amount of fluids proppant etc.) the average reservoir pressure cannot be accurately determined from well shut-in pressures. Fig. 1 shows an example of measured shut-in schemes. We demonstrate the concept with an example involving a decision to be made on where to place a water injector well relative to a

pecially in thin reservoir targets. A new directional electromagnetic (EM) measurement-while-drilling tool (PeriScope*) provides a simultane and gas company indicated a 22 ft thick porous permeable oil-stained sand. Two appraisal wells drilled by Oilexco in 2003 and 2004 indica y.�Integration of these activities however requires a good deal of ‘intelligent’ technologies in the form of systematic data acquisiti alt intrusion leaving the present reservoir at a very steep 45�slope. The reservoir is highly overpressured exhibiting a pressure gradient is still a reinforcing process.� Which means that as soon as potentials are proven to exist resources will be made available to pursue th suitable wellbore trajectories and conformance requirements. At the same time a comprehensive sand production prediction study was car tial to screen regions that are most favorable for well placement. In this paper we present a gradient-based method that is distinct from tho

ion in porous medium.� Solution of the diffusivity equation under different boundary condition forms the basis for prediction of bottom ch is based on solving the same set of equations as is done numerically when using a simulator. Analytical solutions to the diffusivity equati . Two different approaches to incorporate the regularization term have been used extensively in reservoir characterization literatures. One o model before accepting it for practi

inear geological objects such as channels or fractures. The proposed approach addresses these concerns. The number of parameters to

components that partition into either of the hydrocarbon phases and that the water component could not reside in the hydrocarbon liquid ph nsport terms in the equations. For example flow terms can be described by two-point flux approximations or by multi-point flux approximatio completion and stimulation for production enhancement1 2 3. Production logging is very important to identify problems with horizontal we

d interval to not contribute to production. Discussed in this paper is one such factor- pressure change in the wellbore due to undulations in w

residues remain after the breaker reacts with the polymer. It has been postulated that fracturing fluids need a minimum pressure gradient to rast do not show such obvious production peaks but instead sustain a flat production profile or exhibit a slowly increasing production rate on system with isolation mechanical diversion and selective fracture ports allowing the fractures to be placed at specific positions along the based on the multicomponent flow simulation that is done using single computational grid for the reservoir and the fracture. For detailed des s is the vertical overburden stress. In shallow formations the normal stress is low and interfacial slip between formation bedding planes is m lic fracture analytical simulators. The advantage of this method is simplicity and speed. However there are a certain aspects of the problem

dual layer properties that give the best fit to the observed well production history and production log data. Discussion of Non-Linear Regres andface flowing pressure (Pi-Pwf) first reported by Ramey and Cobb6. A thorough investigation on the use of the dimensionless productivi asing (PKN) or low and decreasing (KGD or Radial). The reason why current available models are not adapted to the case of point source n and growth for a given scenario. Many experimental and theoretical studies were devoted to this topic and this paper is another attempt to iven a basic network structure there is a wide variety of ANNs that can be produced. For example different methods or criteria used to train

he Messinian rocks and divided the field into two blocks; the northern downthrown block enclosing the main production area of the field.

as sales and consequently error in production data can be considered minimal. However reservoir pressure is uncertain since limited well m

many experimental studies. Separation in a thermogravitational column with both effects has been measured widely (Schott 1973; Costeseq ttempts to address the painful challenges and highlight the benefits of using the technology.

olumes. Here we apply multipoint transmissibility upscaling which arises if we associate a boundary flux with two control volumes sharing th

vugs that do not have a connection to the overall fracture system.� Vugs can be interconnected with other vugs in the matrix rock.� Su on has been proposed for predicting the pattern of shear/tensile fractures or the pattern of secondary faults and shown promising results (B

plicit approach may also require short time step length. Simulation of geological scale reservoir models with finite difference/finite volume m well known that an explicit numerical method which is used in [16] poses a restrictive CFL constraint on the time step. This constraint is espe complex flow patterns that may develop when a fractured reservoir is produced. Several approaches (e.g. Matthai et al. 2007) have theref

own methodology for the characterization of the uncertainty in reservoir performance predictions given some geologic information on the re

anding where and when the scale forms is important since formation of the scale close to a production well or in the well will reduce the pro

the streamline simulation process: the one determined by the frequency of pressure updates (pressure time step) and the one dictated by on. In this paper we propose a special analytic approach in order to reduce the time required for the flash calculations. Coupled with the com in the San Jorge Basin Argentina. The workflows of interest are identify candidates for infill drilling locations propose a field developmen

m yields continuous pressure data over the life of the well. This could result in an enormous amount of data which can be a serious data h s restriction limited the usefulness of the multisegment well model when investigating wells without packers in the annulus or the effects of

all regions contain gas-condensate (GC) in the Najmah-Sargelu reservoir while Marrat contains both volatile oil (VO) and gas-condensate (F

sumed that non-Darcy flow in their experiments can be described by the Forchheimer equation. According to the convention of the oil and g one the location where water becomes mobile). 2) At any depth in the transition zone what is the oil saturation Soil what proportion (So has caused drilling problems in the past. The drilling conditions would require careful planning since downhole temperatures reached 289ï¿ most of the cases the wells are being drilled without the proper knowledge of stress pattern of the area.� The demand of an in-situ stress or operator and one or more key suppliers. Each of the major operators have their own terminology for “Smart Fields as listed below.ï¿

Sea on the west. The ANS includes the giant Prudhoe Bay and Kuparuk oil fields among several other fields. The ANS land area is approxim of the cement through Hooke’s law. A correction of dynamic values of Young’s modulus and Poisson’s ratio is required to be us

eep depth of investigation gives more immunity to reinvasion. The interpretation is fast and hence allows making an almost real-time decisio ole production monitoring was needed in order to draw the full benefit of the intelligent multilateral completions. This resulted in the installatio Field. The following part summarizes the reservoir properties and production history of the field. Sabriyah Field has oil gravity ranging 18-2 w down-hole as in Chayvo.� Interpretation with a conventional turbine spinner or a full-bore spinner becomes inaccurate in these cases c

ns: �������� ����Keep sampling pressure above the bubble point so that the acquired sample remains rep

r-based-mud filtrate can contaminate water samples because the filtrate is miscible with formation water and chemical reactions can alter t example is the collection of pressure data from permanent down-hole pressure gauges (PDG) to perform pressure transient analysis (PTA) orehole at depth intervals between 4 980 and 6 095 ft. The map view of the treatment and monitoring wells is shown in Fig. 1 along with the lic fracture design execution and evaluation is neither simple nor straightforward. On the contrary this paper will illustrate that depending s

well and the data from this was monitored as the well was put on production. In January 2005 a workover was performed to change the pu e criteria for suspending and transporting entrained liquid droplets in the flow stream upward.� It has been observed by Turner et al3 and porting entrained liquid droplets in the flow stream upward. It has been observed by Turner et al3 and Oudeman11 that the flow stream velo in the late 1990’s revived the interest in temperature log interpretation and new rigorous thermal models were developed for the interp

ndently of the result of the analysis it should be classified and ranked based on the constraint or discipline responsible for the following acti ecision and a geometric arrangement that allows at least one probe to identify the presence of the lightest phase. This paper describes wha

n.2 On the other hand asphaltenes have been reported to become unstable as a result of fluid blending (co-mingling) of fluid streams3 as 1). This field is producing from the Alamien dolomite of the Alamien carbonate member consists mainly of carbonates with subordinate shale mmingling tendencies. Cased-hole surveys might look for bypassed hydrocarbon zones or have objectives that could not be achieved during n the well or reducing flow rate and it can be performed any time during the life of the well. It is based on the fact that over time the individu y problems which may result in operational problems (Davis et al. 2000; Smith et al. 2006). The combined monitoring of passive seismic an n the gas/oil and water/oil contacts. The south flank dips less steeply (20 degrees) and is suspected of having perched oil/water contacts. V ention often leads to insufficient reservoir information for accurately understanding reservoir connectivity drainage and flow assurance. For

eliable data for reservoir modeling and production forecasting. A combination of traditional techniques and computationally intelligent (non-p d and poorly sorted formation sands can be particularly perilous to production measurements. Although some of the more sophisticated pro

eservoir. Time lapse monitoring of a reservoir is estimated at different wells in the field using incessantly developing and evolving through ca

ons. Introduction Peripheral water flooding as pressure maintenance method was commenced within few years of the discovery of the gian the field (Bhatti et al. 2007). Assessing pilot performance and fine-tuning the model’s predictive capabilities requires proper surveillanc rseshoe Canyon coal is expected to produce 3 Bcf/day by 2025. With an average rate of 80 000 cf/day per well this corresponds to 37 000 . 1991 ). Figure 1 displays a schematic of cleat network in a coal bed. The permeability of the cleat system is a reservoir property of prima stresses around open hole completions. The matrix permeability of coal is extremely low so the primary transmissibility system is from coal ctively cleaning up fracture damage caused by the crosslinked gel and the high cost of these massive stimulation treatments the wells wer ear the wellbore (along with sand slugs after initiation).� This technique helps to lower the treating pressure after fracturing and facilitates

me of the large crosslinked treatments previously pumped but less than 10% of the proppant volume.� Well performance was somewhat e to the complex nature of the Barnett reservoirs which is vastly different than that of conventional or other types of unconventional reservoi ower now make simulation of a SAGD pad with multiple well pairs possible so our simulation model was also able to account for the interpla is possible to have both shales and coals interbedded in a single reservoir resulting in gas contributions from both lithologies. ge marine shelf deposit that unconformably lies on the Ordovician-age Viola Limestone/Ellenberger group and is conformably overlain by th mical processes can be modeled by basic fluid flow in porous media coupled with thermodynamic equilibrium among the reactants and produ

pleted. Thus this system achieves which no other existing artificial lift system does. Recirculates power to run itself. Equipment Description ettings. Genetically three types of sediments can be recognized including highly permeable sandstones deltaic distributary channels that in

an planned leaving the higher pressure layers only partially treated. This is becoming more of an issue as development wells are being dri production tests. ave a dramatic effect on the types of flow and flow regimes exhibited in a multiphase flow system. In situations where the outflow velocities ave a dramatic effect on the types of flow and flow regimes exhibited in a multiphase flow system. In situations where the outflow velocities ½ This paper describes the process used to achieve the drilling of about 5 000 ft entirely within the Mauddud reservoir. Geological and Geo

optimization of intelligent completions. To some extent load-balancing problems may be corrected by proper placement of wells if the rese

s used in ESP systems. analysis. The remainder of the paper presents a detailed and sequential SA for a rich data set to demonstrate how parameter interaction fa

d on the high retained permeability results. The six fracture stimulations performed in early 2006 returned incremental rates in excess of 100

oil saturations of 60 to 90 percent depending on its location within the deposition.� Generally up dip to the west and southwest in the Rich 000gal). Fiber addition improves the proppant carrying properties that these low viscosity fluid lack. The low viscosity fluids are also allowing

used to improve fracture geometry and enhance production from propped fracture treatments.� These particular degradable fibers are c servoir rock and in the case of shale an added complication is the hydrophobic kerogen partially lining the pore surface. Further the prese een given including the “composite layer effect “shear dampening and fracture behavior at layer interfaces for the unexpected hei are generally welcomed. To this end a development project was initiated to provide enhancements to viscoelastic surfactant fluid technolo ters in reservoir management processes (Khatib and Verbeek 2002). Water treatment options have been discussed that include desalinatio (Sw) = 48% Avg Net = 110 ft) Middle Williams Fork (favg = 8.5% Sw = 51% Avg Net = 170 ft) and Lower Williams Fork (favg = 8.9% Sw ack became a premier completion technique in the late 1980s 2 when the use of the tip-screenout (TSO) technique earned worldwide accep r that purpose many operating and service companies in Western Siberia have applied various techniques to prevent the breakthrough of th evisit this problem and determine if the technology had been invented which would allow this suspended reservoir to be developed and achi mposition of the matrix is mainly sandstone however there can be a significant carbonate content that can reach 35%. In the southern portio er drainage area. However horizontal well completion has lagged behind in particular when a stimulation treatment is part of the completion

ation treatment. The remaining intervals will therefore not receive the optimized treatment and well production will be less than optimal. T acture width. Both cases produce suboptimal treatment with poorer fracture conductivity and hence poorer well productivity. Another chara process.� The effectiveness of this breaker has been measured in a series of proppant pack conductivity tests demonstrating greater tha

ologic and petrophysical properties often characterize these sands. Drilling and completion of the Morrow wells have been a challenge from

flowing bottomhole pressure above the AOP by reducing the pressure drop taking place in the formation particularly near wellbore. Product in Lafayette February 2006. In a series of lab experiments yield stress measurements ranged from 0 – 17 Pa. This paper builds on the r eam positions and shorelines due to sea level fluctuations caused a large variation in the thickness and aerial extent. 2� Sandstones and

œinfill drilling during which new wells are drilled into unfractured (and hopefully undrained) parts of the reservoir. Wrongly estimated fracture

rimental methodology to characterize acid-etched rock surfaces carefully and then relate the fracture-surface features to the measured frac d of shales siltstones and sandstones. 90% of the production for the Priobskoe oilfield comes from AC-10 AC-11 and AC-12. The main foc cent times the use of radioactive tracers has grown in acceptance. Due to the inherent inaccessibility of the downhole environment radioac

understand the possible discrepancies in prediction results. The range of application of the various inflow equations also had to be determ th the liquid-to-gas ratio and the velocity decrease. This variation of permeability was explicitly modeled in the proppant pack by dividin

e types of porosities coupled with the natural fractures present in the zone and the high bottom hole temperatures (250-280F) results in und

wever in some projects in which multiple observation wells are used (Warpinski et al. 2005) the 3D radiation pattern will be measured bette

g a 3D numerical simulator and investigated the size of the stress reversal region as a function of various reservoir properties. Fracture turn ovides the data on hydraulic fracture simulation accounting for accumulation of damages in elastoviscoplastic medium as well as the effect ed by modeling discrepances/inaccuracies. To reduce the uncertainties and improve fracture design information on the geological geomec

aimed at clarifying the polymer concentration process and confirming the presence if any of a yield stress effect. Experimental Apparatu th the Spar and subsea. Kikeh is planned to be developed with 34 wells; 18 oil producers 15 water injectors and 1 gas injector. Water injec y on the attenuation but also on the total reversion and increase of the oil production that was declining for over ten years (D�ria et al 20 atural fracture and studied conditions that produced crossing blunting or offsetting.12 17 18 21 26 22 24 25�Offsetting where the fracture 02; Clarke et al. 2006) but so far none has presented a rigorous solution for the performance of such wells. This situation is reflected in the reservoir section was drilled with a water-based fluid. Sand prediction models from the operator and the service company teams had indep ecome the field development method of choice in many cases there have been certain limiting technologies on the completion of horizonta come the field development method of choice in many cases there have been certain limiting technologies on the completion of horizontal ot satisfactory. For this reason development of this field through horizontal openhole drains is necessary to achieve acceptable level of prod orthern part of the reservoir(Ref. SPE#81487 by N.G. Saleri). ed in the Oriente Basin Amazon jungle in Ecuador. The main fields are: Paka Sur Field and the Eden Yuturi Fields. Both are clastic reservo

ls and if the predicted inflow does not change significantly with time during production. The well can then be configured so that hydrocarbo sues model laws that relate experimental parameters of the physical model to field-scale prototype parameters were utilized to perform the

ods such as Log Enhanced Resolution using Borehole Image (SHARP analysis) have been developed to improve the reservoir characteriza study. The completion and operational decisions to prevent or control sanding need to be taken on a well to well basis by considering the in wellbore heterogeneity can be further created by the perforating process.� The rock fabric surrounding the perforation tunnel is altered b ng between 12 to 16%; the permeability is in the order of 100-200 md. The reservoir properties are quite homogeneous over the field thus ervoir of� J-10.2 & J-10.1 with J-10.2 being perforated leaving J-10.1 un-perforated (Figure 2). Based on the log analysis J-10.2 sand h of conventional perforating performance was done. This evaluation confirmed the link between poor well productivity and perforating and ju on treatments or by completing the zones with deep-penetration perforating to bypass the invasion damage. Fracture stimulation to improve avoids many of these tradeoffs. Bethany Field The Bethany field is located on the Sabine Uplift in extreme east Texas adjacent to the Lou optimal static underbalance to clean up perforations in these reservoir conditions is ~7000 psi. The reservoir pressure in these cases is well solutions developed for PTT interpretation assume a constant skin factor (Earlougher 1977; Lee et al. 2003). Underbalanced perforating due to pressure discrepancies discovered only after CT was retrieved to surface with an additional run being required. Well does not perfo can serve as a supplemental measure to further verify whether existing guns are adequately qualified within their respective ratings and th

channels lobes and overbank facies and the action of later erosive channels) and complex distribution of fluids saturation in the reservoir 7

ompletions have increased significantly over the last several years.2 3 Until recently standalone screens have been utilized for sand contro d amount of whole core data available for 5 fields required the selection of a sand control system capable of providing well bore stabilizatio

ndatory as well as the isolation of the shale sections to avoid reduction on gravel-pack permeability caused by shale erosion during the grav e and chemistry solutions exist to overcome this problem including diverter valves that are activated sequentially creating a new entry point

ell as while installing sandface completion and low maintenance costs (dilution and solids control costs in reactive silt/shale environments) North Sea Venezuela Brazil Malaysia Indonesia China Australia and western Africa. At least some problems are reported in all areas o d the North Sea Venezuela Brazil Malaysia Indonesia China Australia and western Africa. At least some problems are reported in all ar nd that will penetrate several sand formations of varying quality liner completions with oriented perforations (0/180 or 10/350o phasing) we eing produced where water breakthrough. Pulse tests and tracer study indicated that a short circuit had occurred in the reservoir between th eyed by a rig. However there are instances when sand control is performed through-tubing (rigless intervention) for workover or secondary

on was installed in the Well A to prevent sand production. However sand control measures were not applied across the entire field. A geom set of sanding in wells. This paper describes the methods employed in this investigation provides details of the data acquisition and proces 882 ft in four months and up to 906 ft in ten months. To date no sand control or sand management techniques have been implemented on

as well as production companies has been devoted to developing models for sand production prediction. In terms of the sanding problem c xial tests on reservoir cores. The laboratory-measured mechanical properties were then correlated with the properties derived from openho mprove its performance (Pabley et al. 1982; Crowe et al. 1989). As the viscosity of the acid increases the rate of acid spending decreases a nant influence on the resulting fracture conductivity as long as the strength of the rock can withstand the load.� As the closure stress is in duction by offering data and solutions that were not available in previous years. Likewise technologies often considered archaic by todayâ€

en consistently realized. More recently acid fracturing stimulation has been implemented also in horizontal producers with equally impressiv ells in Tengiz was the use of 15% HCl conveyed by coiled tubing. Spotting the acid in front of the various reservoir layers provided diversio n fluids. Carbonate reservoirs are stimulated using acid to dissolve the rock matrix to create conductive pathways from the reservoir to the

mulation fluids with various mills and scales in the tubular and in the pumping equipment can also upset the optimized acid formulation; caus

action rate with the rock. �However they have the following limitations: (1) they cannot be used at high acid concentrations. This is becau

¿½ This is because the rock structure is significantly altered by the dissolution reaction which increases the permeability contrast between bove 100�C) �deeper Achimov formation. Cenomanian formations that provide the majority of the gas production had represented a g e literature 1 2.� However few studies on the influence of rock properties on the acidization process have been reported 3 4.� Previo ers that govern the success of a restimulation job so as to be able to optimize the treatment for maximum rate of return. Advances in the des he well is producing on average 1 100 Mscf/day. On the second well reservoir characterization was fundamental to select the best stimulati

rmed in Triassic formation. The height of the oil part of this reservoir totals 36-75 m. The height of the gas part equals 56 m. The water/oil

dstone formation as well as formation damage associated with the workover operation. Several wells were treated with this approach in the ring formations for reservoir management ZADCO’s policy is to confirm isolation by physical communication tests regardless of the qu presented in Fig. 2 highlighting the flow and buildup periods we are interested in. In this study Dt is the elapsed time since the beginning o was carried out to establish the potential of the well and shed light on the reservoir structure.� Different phases of the test program can b be the optimum solution indicated on an economic basis or at least a reasonable melding of the optimum economic and technical options c

characteristics are obtained from unique fingerprints such as flow regime lines and points of intersection of these lines that are found on th rvoir produced by a fully completed vertical well in which after the wellbore storage effect the flow regime is predominantly radial before the r the reservoir engineers in the brown fields (mature fields) the challenge in defining the exploitation strategy is the lack of critical reservoir e-rate test or production sequence into an equivalent pressure profile that would have been obtained if the well were produced at a constant

(2006) suggested a two step approach based on multirate transient drawdown tests followed or preceded by a buildup. Firstly he estimate hased development secondary reservoirs development well activation optimization of production mechanisms use of emerging technolog perties on choke changes Higher repeatability measurements to confirm slow trends Circumventing hydrate formation issues downstream

s and industry forums and after several years of development is maturing (Scheers 2004). Some multiphase measurement techniques can ays indicated that the actual production volumes of

en low energy gamma ray measurement the most common one and electromagnetic measurement. The former is the simplest option to ge d difference in scale between grid block and core permeability. Well test data is ideal for bridging the gap between core and grid block perm

of the manipulations employed to reduce the scatter in the resulting derivative data the analyst is often left with data not entirely representa ompleted openhole with sand screens and a gravel pack. External casing packers subdivided the annulus into three zones. An electrical valv

id channels in cement can even provide direct pathways for CO2 leaks that couldn’t possibly be healed by calcite precipitation during th h of rocks generally depend on all of the three principal in-situ stresses it is necessary to estimate the full stress tensor as a function of de

as reservoirs aquifers or coal beds. CO2 has been used in the oil industry as a method to enhance the recovery of hydrocarbons and this k and salting-out. In this article we first discuss in more detail the impact of mutual solubility for CO2 storage in saline aquifers. Numerical im

wn to produce a greenhouse effect. The greatest contributor to global warming over the past century has been carbon dioxide mostly from ough to act as flow barriers over geological periods of time. Delineating such a seal safeguarding its integrity under operational conditions

he well is produced at a rate of 2500 Sm�/day (15700 bbl/day) with production from all zones. Production from the upper zone A would n ing wells until it ceased to be profitable. As a result the field was abandoned in 1997 at this point the final water cut was 71%.

Reef Trend was discovered leading to additional investigations of these reefs.These included works by Mesolello (1974) Shaver (1974) an trations of CO2 is < 1 in 100.� However here is the issue: the mean CO2 content of reservoirs with >20% CO2 is 50% CO2.� In other gives a comprehensive perspective on the use of these cutoffs.[2] The cutoff number most often used in the Oligocene Vicksburg trend of ld be conducted to guide the successful design and application of this technology. Simulation Model and Parameters A 3-D model of a h

erent directions. The fracturing and breaking did not change the rock composition but they strongly altered the structure texture and particu acement. TTIP Technology Overview The TTIP is run in the well on the end of coiled tubing to the required depth and then inflated depend shutoff intervention behind the sleeve in multizone completions is a solution that is not common due to its low probability of success. Shell

oduced water; therefore the volume of fluid produced is limited. In addition production enhancement is restricted.

l data included evaluation of propensity for asphaltene precipitation of the reservoir fluid. In addition the paper also had supplemental data ow rates of both liquids pipe geometry and physical properties of the liquids involved. The flow characteristics of oil-water mixtures are gen pipe flow model was proposed by Zhang and Sarica (2006) as part of a three-phase unified model. Flat interface was assumed for the strat oductive horizons is the ideal method to accelerate production from a single well.�Furthermore marginal reservoirs which are destined perly and lead into proper integrated analysis. The following sections of the work describes phase by phase how a team of Schlumberger cause problems if the fluids in the streams are not compatible3. The mixture of the two reservoir fluids could potentially precipitate asphalte are measured at the representative temperature and pressure condition of the production the model is more likely to represent realistic flui duced or injected for secondary/tertiary recovery can trigger severe corrosion in surface and transport (i.e. pipelines) facilities in hydrocarbo composition i.e. C1 C2-C5 C6+ to identify when the flowing pressure falls below saturation pressure to identify compositional grading3

creases in surface yield. be the amount of gas-in-solution in the liquid phase. Whitson and Torp3 presented a procedure to calculate MBO properties from PVT expe de oils downhole immediately after removing the oil from the formation. maining oil is equally important. In certain environments conventional open hole logs may not fully resolve the fluid content of stacked reser customed or habituated practices to take only one sample from several compartments if where have similar pressure gradients. One far mo

n and hydraulic and thermodynamic communication are of critical importance. Fit-for-purpose design of completion and production facilities

ical spectroscopy can be quite effective to overcome contamination challenges6. The challenge can be much more in the case of determini n surface production and process design and is important for many reasons including the following: Determine which (if any) HSE measur

positional grading can be caused by a variety of factors and often indicates a state of non-equilibrium but it can also be observed in equilibr

ntamination or to some degree of nonrepresentative sampling. In addition it is often difficult in practice to justify the extra cost of taking mult a and hence limit fluid gradient accuracy and reliability. hase envelope of a hydrocarbon fluid mixture although often unpredictable in the reservoir is common: saturated oils are accompanied with ted in real time by a downhole optical fluid analyzer tool which is used as a module of a formation testing tool (Mullins and Schroer 2000; S

n perhaps normally expected and have been observed in several reservoirs throughout the world. This phenomenon is not limited to thick re lack color while low-density hydrocarbons have little or no color. Third the absorption spectrum of water is different from that of crude oils; how many samples to collect. The ability of focused-sampling cleanup to supply virtually uncontaminated fluids—with faster cleanup timeâ

½ If some components in the system are truly non-volatile then there will always be a liquid phase whose presence is independent of the am the occurrence of tight emulsions in the production facilities is quite common. In some cases emulsions may also form in the near-wellbor

near-critical behavior at reservoir temperature must be understood to develop a valid model of the reservoir (Fujisawa et al. 2008). Underst d not occur in the flowline during the critical phase of the operation. This technique yielded very clean samples validated by laboratory ana odelled data from an Equation of State (EOS) software package using data from a PVT report. This requires a competent phase behaviour vior of gas condensate reservoirs in the Siberian region is an essential element of field management. In most cases reservoirs have been p ting. Acetic and formic acids are less corrosive than mineral acids and can be inhibited. ant to execute a matrix stimulation treatment. Among other challenges the Hungarian fields are characterized by their mineralogical comple izing intends to dissolve the damaging minerals that fill line or cement the porosity of the quartz matrix.[Knox 1964]� The identity of thes measures through chemicals with halite inhibition properties. However the current commercial available halite inhibitors are only effective at

mics. In a perforation flow experiment the after-shot sample productivity index (PI) is determined in axial flow and sometimes also in radial ¿½In the damaged zone the pores are much smaller than in the virgin rock: many sand grains have micro-fractures and large pore throat he uniformity of the finding is obviously related to the similarity in the widely spread reservoirs in Western Siberia1-2. This is valid for both th rn profile. When the inhibitor concentration is less than a certain threshold the Minimum Inhibitor Concentration (MIC) the scale protection

or part of ZADCO WIMS. In 2001 ZADCO carried out a scale study to evaluate the scale risk in UZ field. It was found that the the maximum cale management process to ensure that any lessons that can be learned from analysis of the earlier stages of production may be applied d pilot-points (or the grid blocks). During the sensitivity analysis both sensitivity coefficients and the Hessian of the objective function are ev

f numerous strategic analyses on candidate assets at speeds which had previously been considered inconceivable and most importantly

onnectivity. This paper demonstrates that new workflows allow the management of sparse multi-frequency data streams in cases as extrem cquired field data will be used to calibrate the simulation model for production injection saturation and pressure data in order to design as

greater than 1 000 BOPD are typically completed with either ESPs or conventional PCPs. To achieve the advantages of both ESP and PCP

1992; 1995).� Microwave heating effectiveness depends on several parameters; such as heating period amount and type of matter that

ence for further southeast extension has been destroyed by Tertiary uplift associated with recent rifts in East Africa. The shear zone was ide r the gross interval. Well log and core plug porosity values over 50% are common and measured permeability values range up to 5000 md. y oil and natural bitumen reserves and resources of the Siberian platform comprise one of the three largest accumulations in the world the o

ar to date. Geological Setting and Stratigraphy Being a rift and Cretaceous sedimentary basin Muglad basin is located south of Republic o

ough downhole pumps requires 20% to 30% water cuts (WC). High viscosity and resulting friction pressures hinder the submersible pumpâ

dvocated to allow greater dissolutions of secondary reaction products in low pH environments.2 3 In HCl sensitive formations HCl is replac

o compare sector/field data with equilibrium or steady state gradient models of varying complexities.

nitial viscosity from crosslinking too late may result in a narrow near-wellbore fracture impeding proppant transport. Either crosslinking a si

e of the wells show initial production as high as 10 000 bopd. The drilling practices and other damage mechanisms discussed in the next s reduced tubular and production equipment corrosion and less exposure of hazardous fluids to personnel and the environment at the we e at high temperatures therefore requires a retarded acid. Additionally conventional acid treatment of sandstone formations (such as a mu 800 to 1200 meters with dozens of sand beds ranging from one to four five or eight meters thick many of them strongly laminated1. This p water in the formation can also decrease the permeability due to brine precipitation. Zuluaga et al.[14] have reported 15-30% loss in abso er chemistry because they can influence the pH of the solution. Good quality formation-water data can improve the ability to make the right

0 the portion of gas that was tight gas would increase to 26% whereas conventional gas would decrease to 58%. Shale would only increas

ensive pressure maintenance program. Well spacing is between 500-1000 meter in most oilfields and fracture lengths have been constantl ng for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures.

nly the reservoir B4 and B7 put on production. In the first months of 2007 Foukanda field had a production potential of about 3000-3500 bop

ates from past vertical and slant-hole completions led to disregarding the development potential of this reservoir. A field structure map of SF tion have been collected from them. This provides a unique opportunity for evaluating the quality of our model forecasts – the subject of t the Uinta Basin boundary fault on the east by the north-trending Douglas Creek arch on the west by the Sevier north-trending Charleston es from approximately 30% updip to approximately 60% downdip. The study area situated updip has better reservoir quality and produces a e risk associated with stimulating a non-flowing zone results in bypassed pay of unknown potential. Presented here is a proven technique fo

ents is expanding commensurately. Not only DFA characterize fluid physical and chemical properties also it is being increasingly applied for 400 000 BOP from more than 700 production wells. elopment pace well performance maturation increased reservoir characterization information and technology advancements. This somewh

e volume sealed at near hydrostatic pressure. ����3. A pretest is performed: ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ s selected in the central area because it was uneconomic to produce only one reservoir by itself. The initial pilot development was based on

interval. The discovery of the accumulations of HC in the deep Riphean horizons and nonanticlinal deposits in the terrigenous deposits of th

hen one drills a well with Water-Base Mud (WBM) through a transition zone how does one quantify the mobile oil saturation and the associa

Continual advancement/improvement in oil & gas exploration and exploitation practices and better reservoir management has led the indust

ck types are geological entities usually associated with depositional mineralogical or diagenetic attributes. Identifying rock types provide a f f reservoir heterogeneity. Although applications and advantages of these techniques in formation evaluation are well established each has ates have complex pore system distribution. Their complexity lies in the fact that depositional primary pore space is overprinted by both a dia

VT laboratory and it usually takes a long time (months) before the results become available. Also miscible contamination of a fluid sample news wells for bypassed/remaining oil is equally important.� In certain environments conventional open hole logs may not fully resolve th the secondary porosity and their impact on the permeability. This technique was validated from the dynamic behaviour of a well and shows t of this study the geo-cellular model of the Lower Tipam reservoir was prepared incorporating a better understanding of the spatial heteroge urement has good azimuthal sensitivity; this enables gamma ray images to be acquired. Efforts to address the four objectives described abo proaches such as density neutron and sonic logs are used. Image logs and surface logging data have been recognized as being essentia

conductivity due to shale.2 3 4 The dependency of the different developed shaly sand models on their input parameters has a great impa shale.2 3 4 The dependency of the different developed shaly sand models on their input parameters has a great impact on choosing the b rkflow The workflow presented has three basic steps and is described in detail by Ramamoorthy et.al. (2008). At each step of this workflow e image was successful in identifying the thin sand beds which are generally overlooked by the conventional logs. The method is capable t assinoides) capped by a dense bored or burrowed surface.�� By contrast the high stands are dominated by high energy deposits (gra e been applied to improve the evaluation of these thin-bedded reservoirs. This paper highlights efforts placed on the use of NMR logging to

eview of 3D induction technique is discussed first. The important point is to understand how sand resistivity and sand volume fraction are de

is of the pressure derivative reveals that production comes from both natural fractures and layered media in a bilinear flow characterized by the produced solids and sand grains by means of filter systems and hardware enhancements which increase tolerance to high solids conten uation. Borehole images and matching cores might be expected to display the same fractures distributions but in practice some fractures is reported at the top of this formation from many wells. Furthermore an unconformity at the top of the Cretaceous sequence may have fac

istics is commonly used to model geologic facies and petrophysical properties in reservoir characterization. The spatial characteristics of ge atform this evaluation was complemented by the equally near-real-time analysis of high-resolution borehole images to identify the thin bed solutions proposed since the late 1970s. In the three decades that followed four techniques have evolved with time: the first is the deconvo

eorientation around a single producing/injecting horizontal well and then address the problem of a pattern of injecting and producing horizo

for prevention of sanding during production. Wellbores drilled through base salt in the GOM are subject to increased risks of hole closure t

ement elemental spectral device and other conventional open hole logs were chosen as the suitable logging suite to characterize the fractu g the initial discovery 19 wells have been drilled in the field and 8 of them produced commercial oil rates. The results of core investigations

drilled in the Maloichskoe field and 8 of them produced commercial oil rates. The results of core investigations and well test analyses show

Such drilling fluids usually have surfactants as additives and an excess amount may change the wettability of water wet particles in the for

vals. Sandstones composition is rather complex except for the massive quartzitic sandstone bodies because quartz volcanic lithics mica a pretests and rig time might have been spent to acquire fluid information in difficult environments such as thin beds washouts near wellbor

est desired T1. A specific example in the paper demonstrated the idea. A natural question is to ask what porosity accuracy to expect from m

ductivity signature of the reservoir from the production data. Although the short time span of the drilling process can give only an insight into erated during the Mutriba-Tayarat period (Turonian to Base Tertiary) but the trap formation of the Minagish field is post-Eocene. The recent

bsorption properties of reservoir fluid in the visible to near-infrared (NIR) range. Optical spectra are obtained in real time and at in situ cond 5 Furthermore this technique enables the acquisition of samples at different depths with unmatchable vertical resolution. Proper sampling p

to 14% while permeability ranges up to 1000mD with an average of approximately 100mD. As Sarah produces under a strong aquifer-driv val Pressure Transient Tests (IPTT) and showed that possible formation damage does not necessarily increase with increasing overbalance

ons which required special precautions and preparation. The data acquired is outlined and an analysis of the results is given.� We also le to match the pressure transient data acquired in supercharged environment to deduce values of permeabilities initial pressure and produ : optimization and risk assessment which are also interrelated. However ranking and screening of options for the plan should be done only edict fluid behavior. At the top level of structural complexity lie reservoirs with a high degree of compartmentalization where the thickness o

panc S.A. a company that was later acquired by PESA started operations in the block in December 1996. Paper SPE 104034 provides add h 19-20 API in shallow reservoir and 22-24 API in deeper reservoir.� The gas/oil ratios ranges from 100 to 250 scf/bbl.� The reservoir

exploitation production safety and maintenance records. Fig 1 below shows the gross oil and gas production from 1980 through 2003. roaching aquifer and the connate water blue. eaches the horizontal section (Figure 2) and in some cases when the breakthrough occurs at the heel the flow along the horizontal section 00 STB/d as estimated potential whereas B4 sand accounts 90% of total production with an initial production from 6000 STB/d. The driven sible to implement within the prescribed set of functionality traditionally provided in reservoir/FM tools. This paper presents an innovative ap ment. Example control devices include choke settings gas lift injection rates production routing and pump/compressor speeds. These dev raints arising mainly from the current regional gas export scheme had to be taken into account for an optimised field-wide reservoir manag produced. All of the wells are dual string completions with 2 or more perforated intervals.

the production system for every well. The system backpressure is then conveyed all the way back through the well model back into the rese line compatibility and Oil & Gas companies will need to pilot evaluate and recommend changes to the resulting IAM technology which wil perly and lead into proper integrated analysis. The following sections of the work describes phase by phase how a team of Schlumberger a tation and analysis to acceptable levels before the model can be used in predictive mode to derive development strategies.� Although au uire sand control and are completed with perforations inside 7-in or 9 5/8-in casing. More recently short lateral horizontal sidetrack wells a

ce and reverse the rapidly declining oil production rate is a challenge CACT needs to confront. To significantly improve production efficiency nd amount of fluids proppant etc.) to develop a process for real-time decision-making in a changing environment. We strive to develop re ws an example of measured shut-in pressures in different LV reservoirs. Many wells experienced sanding and casing collapse problems du ace a water injector well relative to a fault in a marginal asset. We examine the value of a future measurement of the degree of compartme

ol (PeriScope*) provides a simultaneous solution for a deep reading and azimuthal measurement. This new measurement is based on nove d by Oilexco in 2003 and 2004 indicated much thicker oil sands up to 60 ft thick with an oil – water contact up to 40 ft deeper then origina the form of systematic data acquisition validation processing and information-extraction to support the process of creating and constructin ured exhibiting a pressure gradient of 0.7 psi/ft. Real-Time Data Transmission During the completion design process the operator decid s will be made available to pursue them – but usually not before. Thus identifying and proving the potentials of a field based on a minimu production prediction study was carried out including laboratory work and mechanical earth modeling to investigate sanding tendency for v ased method that is distinct from those previously mentioned. The adjoint method used in optimal-control theory has been used previously f

s the basis for prediction of bottom hole pressure response of a producing well. These analytical solutions are generally applicable for a sin cal solutions to the diffusivity equation which describes the pressure diffusion in a porous medium for a slightly compressible fluid provide ir characterization literatures. One of these approaches is the Bayesian1-7 and the other is the deterministic.8-11 Both approaches have b

erns. The number of parameters to be optimized is reduced to the number of dominating geological patterns present. Geological continuit

ot reside in the hydrocarbon liquid phase. Balance Equations The governing equations include component material balance equations an ns or by multi-point flux approximations. Similarly transport terms can utilize single-point upstream weighting or multi-point high order weigh identify problems with horizontal well performance. Examples locate the entry points of gas/water for high GOR/water cut wells or identify t

the wellbore due to undulations in well trajectory. Production logs are sometimes used to identify problems with horizontal wells1 2 3 4 5. A

eed a minimum pressure gradient to begin the cleanup process in the proppant pack (May et al. 1997) and this has been verified experime a slowly increasing production rate for several weeks or months.[1] A major potential reason for this behaviour given in previous studies wa aced at specific positions along the wellbore (Al-Naimi et al. 2008). Offset oil producers in the vicinity of this well demonstrate relatively hig oir and the fracture. For detailed description of the flow within fracture computational grid is refined around and within fracture using some s ween formation bedding planes is more likely. Many coal bed methane (CBM) formations are at shallow depth and interfacial slip can have are a certain aspects of the problem that are not considered when using these methods that may influence the results substantially. Produ

. Discussion of Non-Linear Regression Method Spivey2 recognizes that for hydraulically fractured wells four different parameters are typi use of the dimensionless productivity index as a design criteria for fracture stimulation design was performed by Meyer and Jacot5.� In t adapted to the case of point source hydraulic fracturing is that they all assume linear flow a legacy of the past of fracturing vertical wells ei and this paper is another attempt to answer this question. Fracture width reduction (so-called pinching effect) is the most critical near-well rent methods or criteria used to train the network produce ANNs that provide different predictions (e.g. the early-stopping and weight-deca

main production area of the field.

sure is uncertain since limited well measurements are usually available and averaging procedures might introduce some uncertainty in the

ured widely (Schott 1973; Costeseque 1982; El Mataaoui 1986). The thermogravitational column consists of two isothermal vertical plates w

with two control volumes sharing the boundary and some other control volumes close to this boundary. This approach is similar to the one

other vugs in the matrix rock.� Such a vuggy rock is illustrated in Figure 1 which is a thin section photomicrograph.� The blue areas a ults and shown promising results (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001). The elastic simulation numerically s

with finite difference/finite volume methods may be impractical due to time constraints. Coarse models can result in numerical smearing of he time step. This constraint is especially severe in the dual porosity case since the flow velocity in fractures is relatively high. One way of r e.g. Matthai et al. 2007) have therefore been taken to accurately describe fracture-fault systems on a grid-block scale e.g. based upon com

some geologic information on the reservoir hard data at well gridblocks and some scattered production data from the first 8 years of produc

well or in the well will reduce the productivity of that well or in extreme cases will cause loss of the well (Mackay and Sorbie 2000). In this p

time step) and the one dictated by the solution of the saturation transport along streamlines (saturation time step). It is apparent that the s h calculations. Coupled with the compositional streamline technique4 the approach further reduces calculation time and thus facilitates the cations propose a field development strategy based on lessons learned from the past in order to know the size of the business from an eco

data which can be a serious data handling issue while using this data. The proposed approach provides a means of condensing the data ers in the annulus or the effects of different packer installations or leakage through packers. In this work we model devices requiring loope

atile oil (VO) and gas-condensate (Figure 1).� The model is thus divided into 10 PVT regions based on segments and reservoirs. PVT a

ing to the convention of the oil and gas industry the beta factor β is generally deduced experimentally from the slope of the plot of the inver aturation Soil what proportion (Sor_imb) of this is immobile under water imbibition and what is the expected fractional flow of water fw u wnhole temperatures reached 289�F and there were depleted pressures along with H2S and CO2 in the reservoir. The through-tubing dr ¿½ The demand of an in-situ stress map therefore is extremely important while drilling a deviated high angle well. The situation becomes e “Smart Fields as listed below.�Throughout this paper the term Smart Field has been used based on its use at the SPE Forum and

ields. The ANS land area is approximately 60 000 square miles plus approximately 70 000 square miles of state and federal waters in the sson’s ratio is required to be used in Hooke’s relationship. The failure point is given by either the tensile strength or the compressiv

s making an almost real-time decision on water shutoff operation so that it can take place immediately after logging. Saturation Measureme etions. This resulted in the installation of Schlumberger downhole flowmeter in Norsk Hydro multilateral well F-29 on the Oseberg S�r fie ah Field has oil gravity ranging 18-26 �API GOR varying 60-350 scf/bbl porosity of 18-22% permeability of 15-60 md bubble point pres ecomes inaccurate in these cases causing reliance on the temperature log which is also difficult to interpret since the geothermal gradient is

hat the acquired sample remains representative. ������������ Ensure that OBM contamination levels are l

r and chemical reactions can alter the true composition. Reservoir water samples are usually collected in open hole with a wireline formati m pressure transient analysis (PTA). Permanent gauge installations feed data to archive systems; the data can then be pulled and analyzed ells is shown in Fig. 1 along with the initial locations of the largest events in the third stage of this treatment. Six injection stages lasting abo paper will illustrate that depending solely on the results of a simple temperature survey can often lead to misinterpretation of data and subs

ver was performed to change the pump which had been found to have insufficient capacity for an electrical submersible pump (ESP). Mon been observed by Turner et al3 and Oudeman11 that the flow stream velocity required to continuously move the liquid film along the condu udeman11 that the flow stream velocity required to continuously move the liquid film along the conduit wall is consistently greater than that odels were developed for the interpretation of DTS data. The combination of permanent installation and continuous temperature curve acqu

ne responsible for the following action to be taken. This procedure helps Asset Team’s track not only the lost production but also the ac st phase. This paper describes what has been achieved with logging tools and interpretation techniques that utilize the latter approach.

g (co-mingling) of fluid streams3 as well as by gas injection during Improved Oil Recovery (IOR) operations.4-8 Waxes on the other hand a of carbonates with subordinate shales. The unit ranges from 235 to 245 ft thick. 2) RESERVOIR GEOLOGICAL FEATURES Based on core es that could not be achieved during the openhole phase. Regardless of the type of survey performed understanding the exploration and ap n the fact that over time the individual layer flow contributions will change naturally as the reservoir layer pressure changes. Flow distributio ed monitoring of passive seismic and surface deformation provides insight into these mechanisms leading to casing deformations and also having perched oil/water contacts. Voidage support will be achieved by both water and gas injection and effective voidage replacement is c drainage and flow assurance. For those wells requiring sand control an additional constraint is that sandface sensors must be deployed o

and computationally intelligent (non-parametric) modeling methods using Neural Networks (NN) and Self Organizing Maps (SOM) working t some of the more sophisticated production detecting tools such as the APLT provide optimum answers of flow distribution it is necessary t

developing and evolving through casing measurement techniques. The ability to detect hydrocarbon behind casing is therefore vital. Two pa

ew years of the discovery of the giant complex carbonate reservoir in the middle-east region. Although initially quite successful the field has pabilities requires proper surveillance planning and timely data gathering. To efficiently meet the pilot objectives while acquiring high-quality per well this corresponds to 37 000 wells in production. Overall Alberta currently produces 21 Bcf/year but this is predicted to increase to 5 stem is a reservoir property of primary importance because commercial levels of production cannot be obtained unless a well-developed na y transmissibility system is from coal cleats or natural fracture systems. These fracture systems (or cleats) are generally much wider than yo timulation treatments the wells were not as economical as desired. In 1997 large-volume high-rate slickwater fracture-stimulation treatme essure after fracturing and facilitates subsequent pumping of the main treatment (commonly slickwater).� However a risk of high viscosity

½ Well performance was somewhat better than the crosslinked jobs but stimulation costs were reduced by approximately 65%.� These t her types of unconventional reservoirs it is difficult to obtain a clear understanding and an accurate description of the reservoir. To quickly ac s also able to account for the interplay between well pairs. s from both lithologies. up and is conformably overlain by the Pennsylvanian-age Marble Falls Limestone (Ketter et al. 2006). Formation thickness varies from 200 rium among the reactants and products. For practical purposes the models can be used to design field scale acid stimulation treatment and

to run itself. Equipment Description The major components of this lifting system are: Inlet Air Compressor Surface Venturi Downhole T deltaic distributary channels that incise the flood valley; massive thick mouth bar sandstones and sheet-type shore terraces reservoirs. Th

as development wells are being drilled in more dense spacing increasing the chances of treating some depleted layers. The Treat And Pr

uations where the outflow velocities are sub-critical the wellbore liquids are not continuously and uniformly transported up the wellbore to th uations where the outflow velocities are sub-critical the wellbore liquids are not continuously and uniformly transported up the wellbore to th ddud reservoir. Geological and Geophysical Considerations in Location Selection: The selection criteria for choosing the well location inclu

roper placement of wells if the reservoir is characterized perfectly a priori. And incorrect well placement may be partially compensated by a

nstrate how parameter interaction factor collapsing and appropriate goodness-of-fit measures can be employed to achieve a parsimonious

d incremental rates in excess of 100% over the predictions at sanction. Post-frac production results suggest that vertical communication thr

o the west and southwest in the Richland County deposit the Bakken Middle Member clean portion has the higher oil saturations as calcula low viscosity fluids are also allowing for lower net pressure rate increase resulting in the possibility to place fractures with longer fracture ha

se particular degradable fibers are continually gaining a favorable reputation worldwide as the technology has evolved and the scope of rele the pore surface. Further the presence of liquid hydrocarbons may adsorb and alter the wettability of the reservoir. These factors make it d er interfaces for the unexpected height containment (Warpinski et al. 1998; Barree and Winterfeld 1998; Wolhart et al. 2004). Alternatively viscoelastic surfactant fluid technology which addressed the need for cost control and provided the ability to use various mix-water fluid typ en discussed that include desalination reverse osmosis and ‘floc ‘n drop’ methods but trucking costs associated with moving wat ower Williams Fork (favg = 8.9% Sw = 51% Avg Net = 175 ft).� Reservoir pore pressure gradients range from 0.42 psi/ft in the Upper W ) technique earned worldwide acceptance as an effective stimulation method for high permeability formations. Modern frac-and-packs invol ues to prevent the breakthrough of the propped fracture but so far without a clear and documented success. This paper describes a combin reservoir to be developed and achieve the planned field production objectives. A task force with team members from both KOC and the ser an reach 35%. In the southern portion of the area considered there are also limestone reservoirs which are often interbedded with sandsto n treatment is part of the completion or has to be applied as a remedial treatment in wells performing below expectations1.

duction will be less than optimal. The industry is searching and experimenting with a variety of methods to stimulate each production inter orer well productivity. Another characteristic discrepancy is underestimation of downhole pressure. Matching of the brittle linear-elastic mod ivity tests demonstrating greater than or equal to 95% retained proppant pack permeability.� Laboratory Fluid Loss Measurements To

ow wells have been a challenge from early 1960s where it was considered that the only good Morrow well was the one that was producing n

n particularly near wellbore. Production improvement can be achieved through the acid fracturing as it will be discussed in details in this pap €“ 17 Pa. This paper builds on the results published earlier9 and demonstrates successful strategies that mitigate the yield stress effects to aerial extent. 2� Sandstones and shales are intermixed throughout the Cotton Valley group resulting in a highly laminated formation.�

reservoir. Wrongly estimated fracture azimuth (and its position) can lead to financial losses. Furthermore the borehole deviation are used n

urface features to the measured fracture conductivity. The preliminary results presented here show how statistical properties of the surface-r 10 AC-11 and AC-12. The main focus of this paper is on the AC-11 and AC-12 formations where production development and enhanceme the downhole environment radioactive tracers have represented one of the few viable means for analyzing the placement and flow of vario

ow equations also had to be determined. eled in the proppant pack by dividing the fracture�into segments and calculating the permeability in each segment.

mperatures (250-280F) results in undesirably high leak-off rates during acid fracturing treatments. Regular HCl acid has high leak-off rates t

ation pattern will be measured better allowing for the possibility of more-accurate fracture planes. Nevertheless the observed seismic radia

s reservoir properties. Fracture turning was also studied using a 2D hydraulic fracture model. plastic medium as well as the effect of inhomogenity of porous media properties on fracture propagation. The problem of fluids displaceme ormation on the geological geomechanical and flow setting is required. This includes stress distribution in the wellbore formation elastic p

ess effect. Experimental Apparatus and Methodology The conductivity apparatus consists of two Ohio sandstone cores (~ 0.2 md) conf ctors and 1 gas injector. Water injection will peak at 260 000 BWPD. for over ten years (D�ria et al 2005). Until 2000 the results of the hydraulic fracturing operations in the Carm�polis field were below th 4 25�Offsetting where the fracture crossed a natural fracture was observed in many of these laboratory experiments and was recognized ells. This situation is reflected in the software domain (or perhaps reflects it) where most commercially available nodal analysis packages c e service company teams had independently confirmed that this well was a good candidate for a cased and perforated completion with orie ogies on the completion of horizontal wells that have proven to slow that growth. This is primarily the ability to effectively stimulate or fracture gies on the completion of horizontal wells that have proven to slow that growth. This is primarily the ability to effectively stimulate or fracture y to achieve acceptable level of production. Openhole completed reservoirs will lead to higher productivity index but usually damage due to

uturi Fields. Both are clastic reservoir with variable fluid and rock properties. Fluid viscosities varies in the field from �5 cP 8 cP 12 cP 1

en be configured so that hydrocarbon production (or some other objective function) is maximized by optimizing the inflow profile along the w ameters were utilized to perform the block test and interpret some of the experimental observations7 8 9. The experiment was designed to

o improve the reservoir characterization of these thinly bedded reservoirs (Ref. 2 and 3). After reservoir characterization other frequently a ell to well basis by considering the individual characteristics of each well. The well characteristics include inclination and orientation in the inng the perforation tunnel is altered by the high pressure impact of the jet and the perforation tunnel itself can be filled with rock and charge e homogeneous over the field thus providing optimum candidate wells for the initial evaluation of the new perforating technique. Backgroun d on the log analysis J-10.2 sand has 6.8m TVD net pay with average effective porosity of 15% and permeability of 26md followed by wate ell productivity and perforating and justified the field trials of new technology in this area. Most of the perforating technology developments h age. Fracture stimulation to improve single-well productivity is a risky operation in the HZ fields because the thin pay sandstones often have eme east Texas adjacent to the Louisiana state line as shown in Fig. 1. Bethany was discovered in 1916 and has produced over 1.6 Tcf ga rvoir pressure in these cases is well below this optimal pressure so meeting this requirement is impossible. Also executing a job with such a 2003). Underbalanced perforating has been widely applied to well completion. An UBP induces pressure transient that provides an opport being required. Well does not perform as expected due to insufficient underbalance condition. Guns sanded in due to higher than expect within their respective ratings and therefore will be useful to both perforating job planners and perforating system developers. A second app

of fluids saturation in the reservoir 7 pilot wells were drilled during the planning phase prior to 2002. This pilot program led to a developmen

ns have been utilized for sand control in majority of horizontal completions.4� Many of these wells have failed prematurely due to either p ble of providing well bore stabilization in all production wells. Shale Characteristics The deepwater Angola fields are located in shallow imm

sed by shale erosion during the gravel placement. To avoid well internal diameter reduction or high completion cost an intensive laboratory quentially creating a new entry point upstream into the wash pipe 6 light weight gravel which allows lower pump rates for the same alpha-wa

in reactive silt/shale environments).[1] Openhole high-inclination gravel packing is the preferred technique adopted by many operators in problems are reported in all areas of the world where oil and gas is produced. some problems are reported in all areas of the world where oil and gas are produced. ions (0/180 or 10/350o phasing) were ranked higher than more traditional mechanical sand control options. Stand Alone Screen (SAS) solu occurred in the reservoir between the two wells where it took 2 hours 50 minutes to travel from surface to surface. The wormhole dimensio vention) for workover or secondary pay sands4&5. Prior to screenless completions sand control options for these secondary targets have b

plied across the entire field. A geomechanics study conducted in 2004 (Sarir Sanding Study Phase I1) examined seven wells in the south e s of the data acquisition and processing required and demonstrates that accurate sanding predictions can be achieved by focusing effort o hniques have been implemented on a field wide basis for the field. Due to fill in the borehole the production for this field is obstructed to a lo

n. In terms of the sanding problem clastic reservoirs can be divided into three groups according to the strength of the reservoir rocks whic the properties derived from openhole logs. The magnitudes of the in-situ stresses and formation pressure were derived from analysis of op he rate of acid spending decreases and as a result deeper acid penetration can be achieved (Deysarkar et al. 1984). The addition of uncro e load.� As the closure stress is increased surface features along the fracture faces may be crushed and the fracture conductivity is more often considered archaic by today’s fast paced standards continue to pay dividends when properly integrated with the new technology a

ntal producers with equally impressive results. us reservoir layers provided diversion of the acid. Results of laboratory tests in which viscoelastic diverting acid systems were injected thro pathways from the reservoir to the wellbore.[1 2] The conductive channels (“wormholes) bypass the damage created during the drillin

the optimized acid formulation; cause adverse reactions with the formation minerals; and further aggravate the overall complex chemistry in

gh acid concentrations. This is because of the limited solubility of their calcium salts. For instance acetic and formic acids are typically used

s the permeability contrast between the treated and the untreated zones.� Unless effectively diverted the treated region eventually beco gas production had represented a great challenge for stimulation in Western Siberia until�last year. Most of these gas fields are in produ have been reported 3 4.� Previous studies on the influence of injection rate have shown that characteristic dissolution patterns are obse m rate of return. Advances in the design and evaluation software improved diagnostic techniques etc have played a key role in restimulatio damental to select the best stimulation practice considering the fact that this well was a direct offset form a well drilled and completed in 19

gas part equals 56 m. The water/oil contact has been established at a level of 3168–3404 m. The reservoir is fully or partially stratified an

ere treated with this approach in the past but the results showed not to be very cost effective considering the complexity of the operation as munication tests regardless of the quality of cement interpreted from cement bond logs. The policy is applied selectively however. Only ceme elapsed time since the beginning of inflow of fluid and Dtp is the duration of flow period. When Dt > Dtp it indicates a time within the shutent phases of the test program can be summarized as (see Figures 2 and 3). Initial clean-up on full choke followed by a shut-in period to le m economic and technical options considered. An innovative robust and unique production optimization methodology is reported in the pa

n of these lines that are found on the log-log plot of pressure and pressure derivative. It isapplied to both drawdown and buildup tests. Sev me is predominantly radial before the effect of any outer boundary. Note that this may not be true for wells in nonhomogeneous and heterog ategy is the lack of critical reservoir information such as pressure and permeability.� Many times old information based on few scattered m he well were produced at a constant rate for the entire duration of the production history. If such an objective could be achieved with some

ded by a buildup. Firstly he estimates reservoir parameters (k s D and p*) with transient data rather than doing the traditional deliverability hanisms use of emerging technologies understanding heterogeneities and replacement and upgrading of equipment. The Abu Al Bukhoos ydrate formation issues downstream of surface production chokes plugging up controls in separators Remote unmanned operations Lower

hase measurement techniques can perform better and the meters provide a more compact solution than the traditional separation approa

he former is the simplest option to get the multiphase meter as less complex as possible. Indeed the high energy gamma ray being already p between core and grid block permeabilities because it samples the reservoir on the scale of the grid block size. The authors recognized th

left with data not entirely representative of the well/reservoir system under investigation. In this paper we describe a new technique for diffe us into three zones. An electrical valve which also recorded the annular and tubing pressure controlled inflow to each zone (Fig. 2). The 21

aled by calcite precipitation during the CO2 attack. Some of the phenomena listed above can be predicted but cannot easily be controlled; full stress tensor as a function of depth. Yet no single measurement technique can solve for all the 6 independent components of the stress

recovery of hydrocarbons and this knowledge has contributed to extending the use of CO2 not only for enhanced oil recovery but also for lo orage in saline aquifers. Numerical implementation of these concepts is presented. Simulations for a pre-injection study for a CO2 injection i

as been carbon dioxide mostly from deforestation and fossil fuel burning. Methane is second and arises from coal deposits leaking natura egrity under operational conditions and verifying whether isolation is effective or not are key objectives in achieving a successful storage pr

ction from the upper zone A would not have been possible without a controlled production from the other zones hence adding value to the al water cut was 71%.

Mesolello (1974) Shaver (1974) and (1977) Huh (1976) and Nurmi (1977). One of the more prolific workers on these structures during th >20% CO2 is 50% CO2.� In other words when CO2 is abundant it is frequently so abundant. Furthermore high CO2 concentrations are in the Oligocene Vicksburg trend of South Texas is 15-16% porosity (Fig. 2). More recently there has been success at much lower porosity nd Parameters A 3-D model of a hypothetic field is used in this study.�The field is produced by natural depletion without considering an

ed the structure texture and particularly the petrophysical characteristics of the basement rocks. The petrophysics characteristics of altere ired depth and then inflated depending on the type of the application being performed and once the desired treatment is pumped the pack its low probability of success. Shell Petroleum Development Company Nigeria and Schlumberger successfully carried out this operation in

restricted.

e paper also had supplemental data of asphaltene precipitation propensity when contacted with gas either in the form of gas injection from s eristics of oil-water mixtures are generally different from gas/liquid systems. The differences in characteristics are caused mainly by the larg interface was assumed for the stratified oil/water flow. The transition from stratified flow to dispersed flow is based on the balance between ginal reservoirs which are destined to be uneconomic with dedicated production could become viable for production.�The application o hase how a team of Schlumberger and PEMEX specialists with reservoir production and process engineering expertise developed and im could potentially precipitate asphaltene at their commingling point. This problem might occur when fluids of very different densities are mixe more likely to represent realistic fluid behavior. The objective of this paper is to demonstrate the variation in the measured flow assurance .e. pipelines) facilities in hydrocarbon production. Combined with the high temperature pressure and stress associated with drilling comple to identify compositional grading3 to identify reservoir compartmentalization4 5 to measure in-situ pH6 to monitor the cleaning-up proc

ulate MBO properties from PVT experimental data of gas condensate. Coats2 also presented a different procedure for gas condensate fluid

ve the fluid content of stacked reservoirs. In Kalimantan Indonesia it is common to have low resistivity pay zones which can contain signific milar pressure gradients. One far more risky practice is trying to infer PVT properties of formation fluids from pressure gradients based on s

completion and production facilities and optimal planning of reservoir production strategies depend strongly on adequate characterization o

much more in the case of determining small amounts of mobile oil in a gas expanded zone drilled with OBM. A focused sampling device is etermine which (if any) HSE measures must be implemented for dealing with H2S at the various stages of exploration appraisal developm

ut it can also be observed in equilibrated systems when chemical potential gradients are balanced by gravitational potential gradients. Temp

o justify the extra cost of taking multiple samples in a small interval without some indication of fluid variations. It is much more preferable to

saturated oils are accompanied with a phase transition and a gas cap in the reservoir. Interestingly also pressure and temperature ranges ng tool (Mullins and Schroer 2000; Smits et al. 1995; and Crombie et al. 1998). This is accomplished by using a technique of monitoring OB

phenomenon is not limited to thick reservoirs but is observed also over relatively short vertical columns. This is also not only limited to reser er is different from that of crude oils; this enables one to easily identify and quantify the amount of water in the tool flowline. Fluid from the fo ed fluids—with faster cleanup time—further ensures optimal DFA results.11 12 Current DFA techniques use the absorption spectroscopy

e presence is independent of the amount of energy in the system.� Similarly if components are characterized as non-condensable then ns may also form in the near-wellbore region leading to emulsion blockage of porous media (Kokal et al. 2002). In addition to formation blo

voir (Fujisawa et al. 2008). Understanding the nature and composition of formation water is also critical to the economics of field developm samples validated by laboratory analyses – four out of six bottles were full and pressured-up; two were not completely full but clean. This uires a competent phase behaviour specialist to generate and control the generated fluid data (Ref [2] [3]). A MFM could be located anyw most cases reservoirs have been producing below their dew point over long period due to pressure depletion caused by intense productio

erized by their mineralogical complexity and elevated temperature gradients. Algyo field (sandstone reservoirs of deltaic origin) is not an ex .[Knox 1964]� The identity of these damaging compounds can vary from drilling mud particle invasion migratory fines (typically aluminos halite inhibitors are only effective at high concentrations (>250 mg/L). This high MIC (Minimum Inhibitor Concentration) requires high dosag

al flow and sometimes also in radial flow. From the pre- and post perforating flow measurements the core flow efficiency (CFE) of each sam icro-fractures and large pore throats are filled with small fragments (Figure 2).�This decrease in pore size results in the damaged zone n Siberia1-2. This is valid for both the oil-bearing as well as the water bearing formation that is the source of the injection water that is used entration (MIC) the scale protection becomes ineffective and a retreatment is necessary. However the task of predicting the treatment-life o

It was found that the the maximum Scaling Index (SI) (need to explain what is scale index) for mixtures of UZ formation water and injected stages of production may be applied to ensuring effective scale control to the end of the field life cycle.�It is the results of that review pro sian of the objective function are evaluated at pilot points. Ideally the points should be located at the points of maximum uncertainty from a

conceivable and most importantly within the defined hours of a typical working day.� This has resulted in demonstrable productivity incr

ncy data streams in cases as extreme as those where data is input manually in mature assets.� We illustrate this achievement with the e pressure data in order to design as an optimum field development scheme for the lower reservoir units in the southern part of the field. (Re

e advantages of both ESP and PCP production methods and to reduce the lifting cost a bottom-drive PCP system was evaluated for the pr

iod amount and type of matter that will be subjected to the microwave irradiation the cell material that the matter will be placed in (Datta an

East Africa. The shear zone was identified by geophysical means and has been demonstrated to experience right lateral movement in the C eability values range up to 5000 md. The 1st Eocene reservoir has an average depth of about 1000 feet and a gross thickness of about 750 est accumulations in the world the other two being the Western Canada basin and the Eastern Venezuela basin 1. Understanding the natu

basin is located south of Republic of Sudan. Tectonics was complicated by faulting and continuous fault movement and several sub-basins

sures hinder the submersible pump’s ability to deliver heavy oil to surface when water cut is lower than 10%. Introduction The Nukhul fo

l sensitive formations HCl is replaced with an organic acid such as acetic or formic acid.7 Various methods were suggested to retard the tr

nt transport. Either crosslinking a single organometallic system too early or too late risks premature screenout. (Nolte 1988 Walser 1988 A

mechanisms discussed in the next section restrict most of the wells from producing to their potential from reservoir engineering consideratio nnel and the environment at the wellsite. These benefits ultimately lead to a high success rate of sandstone acidizing and sustained produ sandstone formations (such as a mud acid treatment) involves many stages of fluid which increases the complexity of the treatment. An alt of them strongly laminated1. This productive intervals were formed during the Cretaceous period and is of continental origin covering seve have reported 15-30% loss in absolute permeability due to precipitation. An alternate method to enhance water removal is to increase th improve the ability to make the right decisions early in development planning. These data can give information about compartments and co

se to 58%. Shale would only increase to 3% of the volume and CBM would increase to 13%. With the increased percentage of gas being tig

racture lengths have been constantly increasing within the last few years. Moreover it is also quite common that the ongoing water injection ell as among nearby fractures.

on potential of about 3000-3500 bopd with 6 producer wells (5 in the reservoir B4 and 1 in the B7) and 2 injector wells (2 in B4 and 1 in B7)

eservoir. A field structure map of SF is shown in Fig. 3. In 2004 the first horizontal sidetrack well was successfully completed in the low per model forecasts – the subject of this discussion. The reservoir characteristics of subject fields located in the Greater Green River and Pic he Sevier north-trending Charleston-Nebo thrust (that extends into the basin) and on the south by the Laramide north-trending San Rafael a ter reservoir quality and produces a very small amount of water which is probably water from condensation and rock compaction. The rese sented here is a proven technique for quantifying pay and sizing hydraulic fracture design options. The net height of laminated sand evaluat

so it is being increasingly applied for formation evaluation. Nowadays using WFT it is highly possible to simultaneously characterize extrem

nology advancements. This somewhat haphazard and quite often protracted end-state can lead to less than optimal surface kit footprint pa

������������a. A piston is pulled back to expand the flowline volume thus reducing the pressure in the flo itial pilot development was based on massive hydraulic fracturing accompanied with a lift system [i.e. electrosumergible pumps (ESPs)] to

osits in the terrigenous deposits of the Vendian in the southern boundary of the zone was predicted. Nonetheless technical capabilities of e

mobile oil saturation and the associated relative permeability? Assuming a typical scenario in which decisions about where or even whether

voir management has led the industry in maximization of the recovery from producing fields and from new oil discoveries too. Most importan

es. Identifying rock types provide a framework for mapping their distribution which in turn helps to define the geometry of reservoir and non ation are well established each has limitations that should not be overlooked. In general these measurements can be divided into two cate re space is overprinted by both a diagenetical and a stress history responsible for dissolution dolomitisation fractures or stylolites for insta

ble contamination of a fluid sample by drilling-mud filtrate reduces the utility of the sample for subsequent fluid analyses. However the amo en hole logs may not fully resolve the fluid content of stacked reservoirs.� In Kalimantan Indonesia it is common to have low resistivity p amic behaviour of a well and shows promise in understanding the performance of the water sweep at the later stage of field development. understanding of the spatial heterogeneity flow unit definitions and the fault compartmentalizatio ess the four objectives described above have led to the design of a tool with unprecedented application for formation evaluation. We will dis e been recognized as being essential for correct petrophysical characterization of these reservoirs.

ir input parameters has a great impact on choosing the best and suitable model to be used. The uncertainty in the input parameters for the has a great impact on choosing the best and suitable model to be used. The uncertainty in the input parameters for the different shaly sand 2008). At each step of this workflow there are log displays and cross-plots to check results against available core data. These checks will be tional logs. The method is capable to provide a more accurate estimate of net reserves. Facies or rock type classification using the artificia minated by high energy deposits (grainstone layers cross bedding etc.) rich in macrofossils.� Vugs are developed in some intervals.� laced on the use of NMR logging to delineate reservoir properties to a finer resolution than convention tools. In addition the use of images a

vity and sand volume fraction are derived and the effects of the input parameters on the results. Next we show how to use NMR to verify th

dia in a bilinear flow characterized by a slope of � (m = 0.25) of the Log-Log pressure-derivative plot (Azzouguen et al 2000). rease tolerance to high solids content; such that the presence of solids does not plug the formation tester tool or damage the pump module ons but in practice some fractures interpreted in images are often not to be seen in the cores. Likewise some fractures that are occasiona Cretaceous sequence may have facilitated lateral and or intra-formational migration of hydrocarbon into the Tayarat Formation reservoir uni

tion. The spatial characteristics of geostatistical methods in variogram kriging and stochastic simulation make them the tools of choice for r hole images to identify the thin bed reservoirs with the best productive potential. The following sections describe the workflow and the deta ed with time: the first is the deconvolution of low resolution logs a good account can be found in Looyestijn’s 1982 paper1. The second

ern of injecting and producing horizontal wells. Many cases with varied reservoir properties and stress conditions demonstrate the importanc

t to increased risks of hole closure that might be attributed to the complex and rapidly varying formation stresses. In addition drilling throug

gging suite to characterize the fractured carbonate reservoir rocks. s. The results of core investigations and well test analyses showed that the productive unit “M consists of a complex fractured vuggy-po

igations and well test analyses showed that the productive unit “M consists of a complex fractured-vuggy-porous type of a reservoir. A p

bility of water wet particles in the formation to oil wet.� These particles which are originally immobile may then be mobilized and can cau

ause quartz volcanic lithics mica and minor accessory heavy minerals are present in the rock composition concurrently with thin shale-silt s thin beds washouts near wellbore alterations tight formations etc. where it may be more efficient to utilize NMR data. Hydrocarbon type porosity accuracy to expect from modern NMR acquisition modes over a wide range of inversion parameters and noise."

process can give only an insight into the nearer wellbore vicinity valuable information about the reservoir can be obtained. Productive reser ish field is post-Eocene. The recent Mishrif layering scheme divides the reservoir into 9 geological surfaces (time lines at field scale). There

ained in real time and at in situ conditions and fluid composition is derived from the signature using the proportion of methane (C1) ethane ertical resolution. Proper sampling practices are essential to preserve the composition of the extracted fluid as close as possible to that in th

roduces under a strong aquifer-drive directed from the northern flanks and bottom of the field. The low mobility-ratio of oil and water phase ncrease with increasing overbalance.� Some operational aspects of wireline formation testing have been discussed for such environmen

of the results is given.� We also discuss how acquired data and results were later used for field management. During the WFT survey t meabilities initial pressure and productivity index. The model is generalized and is equally valid where supercharging effect is not profound. ons for the plan should be done only after taking the risk factors into account. Therefore an iterative procedure is required which generally c mentalization where the thickness of the main flow units is below the resolution of current surface seismic technology and stratigraphical c

96. Paper SPE 104034 provides additional background information on the structural complexity of the block general stratigraphy and the re 00 to 250 scf/bbl.� The reservoir is supported by strong water drive however most strings require artificial lift due to low reservoir pressur

oduction from 1980 through 2003.

the flow along the horizontal section may be altogether inhibited. Practices have been reported to optimize well placement drilling comple uction from 6000 STB/d. The driven mechanism has been identified as solution gas and water drive. his paper presents an innovative approach for extensibility and flexibility providing many previously unavailable possibilities for advanced F ump/compressor speeds. These devices are often manipulated through remote actuation which means that the engineer can make an adju optimised field-wide reservoir management plan. A recent full field review[1] confirmed the presence of a strong aquifer drive throughout the

ugh the well model back into the reservoir in order to account for the changed boundary condition imposed by the surface model in the rese resulting IAM technology which will evolve through a number of rounds of deployment. Collaboration that has never been seen before in hase how a team of Schlumberger and PEMEX specialists with reservoir production and process engineering expertise developed and im lopment strategies.� Although automated methods exist that assist in the history-matching task the uncertainty reduction in deterministic lateral horizontal sidetrack wells are being completed with expandable sand screens in openhole wells making water control difficult to ac

cantly improve production efficiency of the remaining potential attic oil locations horizontal well is the first priority among various alternative nvironment. We strive to develop reservoir understanding and characterization as elements that constitute the baseline to maximize the su ng and casing collapse problems due to compaction during production which resulted in lower gas recovery. Well histories are quite compli rement of the degree of compartmentalization caused by this fault.

new measurement is based on novel symmetric transmitter-receiver configurations. In favorable conditions such as in thick resistive beds m ntact up to 40 ft deeper then originally encountered on the 1990 appraisal well. Oilexco generated a field development plan based on an in process of creating and constructing new wells based on measurements acquired from existing wells.��� One activity is the task o n design process the operator decided to introduce one PDG in each of the final wells (Fig. 1). A high-resolution quartz gauge was position entials of a field based on a minimum of data time efficiently is a key for unlocking these potentials. Target of the Approach Most of the fie o investigate sanding tendency for various completion scenarios on the shallow and deeper reservoirs. Decision and risk analysis complete ol theory has been used previously for optimization of injection and production rates in a fixed-well configuration (Ramirez 1987 Asheim 198

ons are generally applicable for a single well and used widely in the area of well testing.�The efficiency of analytical models is generally a slightly compressible fluid provide the basis for such a technique. They have been successfully used for well testing applications for many inistic.8-11 Both approaches have been successfully applied for conditioning geological models to production history and comparison betwe

tterns present. Geological continuity is preserved and the optimization problem is formulated in such a manner that geostatistical paramete

nent material balance equations an energy balance equation mass equilibrium equations and saturation and composition constraint equa hting or multi-point high order weighting schemes. gh GOR/water cut wells or identify the non-productive intervals that may need workovers. The challenges and proper production logging me

ems with horizontal wells1 2 3 4 5. Accordingly appropriate technologies can be applied to solve these problem such as shutting off the hig

and this has been verified experimentally (Ayoub et al. 2006). The fracturing process depending upon reservoir-matrix permeability can ca haviour given in previous studies was the fracturing fluid. Commonly cross-linked polymers facilitate hydraulic fracturing treatments the f this well demonstrate relatively high levels of total well production but recent production logging results confirmed that contribution is dom nd and within fracture using some special techniques for proper grid construction. Such approach was used in�� papers2 3-6� and w depth and interfacial slip can have an important effect on fracture propagation in such formations. In this paper we present a fracture hei ence the results substantially. Production forecasting in horizontal wells suffers even more when using simplistic methods because the ver

s four different parameters are typically available for use as matching parameters i.e. permeability fracture half-length fracture conductivi ormed by Meyer and Jacot5.� In that investigation the authors developed a general solution from resistivity theory for computing the dime e past of fracturing vertical wells either open hole or across long perforated intervals. In such cases indeed the flow source is assumed to effect) is the most critical near-wellbore phenomena as it may significantly increase the treating pressure and may result in early screenou the early-stopping and weight-decay methods.) Also two or more neural networks can be combined to produce an ANN with better error pe

ht introduce some uncertainty in the computed reservoir pressure history. PVT data can be also uncertain since some reservoirs have no rep

sts of two isothermal vertical plates with different temperatures separated by a narrow space. The space can be either without a porous med

This approach is similar to the one proposed in [10] with the following major differences: we obtain multipoint flux transmissibility coefficien

otomicrograph.� The blue areas are vugs. The elastic simulation numerically simulates the structural deformation of the reservoir by solving linear elasticity equations under given bo

can result in numerical smearing of flood fronts and grid orientation effects may also be observed. tures is relatively high. One way of removing the CFL constraint is the use of an implicit method for the saturation transport along streamline id-block scale e.g. based upon complex gridding schemes in which fractures are represented explicitly either as volumetric grid cells or as

data from the first 8 years of production. Then participants were asked to predict cumulative oil production for 16.5 years of total production

(Mackay and Sorbie 2000). In this paper various scenarios will be considered where modelling of in situ scale precipitation is conducted us

time step). It is apparent that the streamline simulation can be much faster than a conventional sequental method (e.g. IMPES [11]). The g culation time and thus facilitates the modeling process for large reservoirs. the size of the business from an economic point of view identify benefits through optimizing infill locations using data mining methodology.

es a means of condensing the data into few parameters which are nevertheless quite rich because they describe the patterns in the data. rk we model devices requiring looped flowpaths by extending the multisegment well model in a full-field simulator (Schlumberger 2008a 20

on segments and reservoirs. PVT analysis of different samples from the NKJC shows that the hydrocarbon fluids are generally at near-crit

rom the slope of the plot of the inverse of the apparent permeability 1/kapp vs. a dimensional pseudo Reynolds number V/μ (also called th xpected fractional flow of water fw under production? We share our experience from certain Middle East reservoirs of the behavior to be the reservoir. The through-tubing drilling campaign was chosen as the best option because it would reduce risks and the costs associated angle well. The situation becomes exceedingly critical if the drilling is being carried out in a tectonically active region involving multiple fault d on its use at the SPE Forum and it is intended that any of the following terminology could be substituted by the readership.1 2 Operator

es of state and federal waters in the Beaufort and Chukchi Seas. The Alaska North Slope petroleum province corresponds to the portions o he tensile strength or the compressive strength of the cement (using the Mohr-Coulomb failure criterion for the latter) depending on the exp

after logging. Saturation Measurements Behind Casing Three main types of data are used in saturation monitoring: through-casing resistivit well F-29 on the Oseberg S�r field. The well was completed with flow control of both the main bore and lateral bore with flow measureme bility of 15-60 md bubble point pressure of 300-1900 psia and oil viscosity at the bubble point ranging 2.5-15 cp. Uncertainties of the fluid ty pret since the geothermal gradient is essentially zero in a horizontal well.� Interpretation gets more difficult once water breakthrough occu

that OBM contamination levels are low such that samples are of high quality and DFA data is valid. ����������ï¿

d in open hole with a wireline formation-testing device equipped with a probe or packer module pumpout module and sample chambers. At ata can then be pulled and analyzed on a regular basis to determine reservoir properties such as kh product skin and current reservoir pre ment. Six injection stages lasting about 30 minutes each were utilized to stimulate the six depth intervals ranging between 30 to 100 ft in leng o misinterpretation of data and subsequently inadequate preparation for treatment success. The key to success is in applying multiple tech

rical submersible pump (ESP). Monitoring of the temperatures along the wellbore using the DTS system continued through 2005. move the liquid film along the conduit wall is consistently greater than that required to suspend and lift the entrained liquid droplets upward i wall is consistently greater than that required to suspend and lift the entrained liquid droplets upward in the flow stream. As noted by Turner d continuous temperature curve acquisition overcame problems with early temperature log interpretation by providing large data sets to prop

y the lost production but also the action that needs to be taken in order to reduce it as soon as possible in such a way that a performance m s that utilize the latter approach.

ons.4-8 Waxes on the other hand are also high molecular weight highly saturated organic substances.� The formation of wax crystals d OGICAL FEATURES Based on cores Alamein dolomite of R field is a massive hard to very hard dolostone. Mostly it is medium-grain size nderstanding the exploration and appraisal or field-development objectives and translating these into acquisition objectives is essential for s r pressure changes. Flow distribution is monitored using a permanently installed fiber-optic distributed temperature system (DTS). During e ing to casing deformations and also potentially identifies circumstances that may lead to casing failures. The combined monitoring also can d effective voidage replacement is considered critical to optimum reservoir drainage (Fig. 2). The development strategy of the Azeri field re andface sensors must be deployed on a separate completion run. Historically subsea wells have lower total production compared with equi

f Organizing Maps (SOM) working together in a production performance workflow solution can help to overcome these limitations. To do so of flow distribution it is necessary to consider technology and technique that functions with a high degree of reliability in these oftentimes h

hind casing is therefore vital. Two parallel and complementary methodologies have been evolved over the years and numerous patents and

nitially quite successful the field has experienced uneven distribution of water flood front vertical and lateral sweep due to reservoir comple bjectives while acquiring high-quality inter-well data traditional methods were enhanced by the addition of more advanced (deep reading) m but this is predicted to increase to 540 Bcf/year by 2014 with current booked reserves of 263 Bcf. Alberta alone is predicted to have 500 T obtained unless a well-developed natural fracture system is in communication with the wellbore (Mavor et. al. 1994) The degrees of cleating s) are generally much wider than your average pore throat in a clastic rock and therefore are much more susceptible to fluid invasion dama ckwater fracture-stimulation treatments were sought as a less-expensive alternative. Although well performance was not increased drastical � However a risk of high viscosity slugs is to leave residue and thus lower the fracture conductivity at its entry point with the wellbore. In

d by approximately 65%.� These treatments have become the norm in the Barnett because of the extremely large fracture surface area th cription of the reservoir. To quickly acquire knowledge and guide imminent placement (well spacing and pattern) designs various well spacin

ormation thickness varies from 200 to 800 ft through the reservoir. The productive rock is typically a black organic-rich shale with ultralow p scale acid stimulation treatment and to predict the performance of the stimulated wells. For carbonate acidizing on the other hand the chem

essor Surface Venturi Downhole Tubular and Valves Air Turbine Inlet Air Compressor As shown in the subsequent calculations the prim t-type shore terraces reservoirs. The PK group of reservoirs deposited in the deltaic coastal setting. AS reservoirs are associated with the d

e depleted layers. The Treat And Produce (TAP) Completion system has been developed to allow the efficient treatment of individual layers

mly transported up the wellbore to the surface.� Turner et al1 identified that there are two transport mechanisms that must be considered mly transported up the wellbore to the surface.� Turner et al1 identified that there are two transport mechanisms that must be considered a for choosing the well location included the results obtained from detailed geophysical petro-physical and sedimentological analysis; and g

may be partially compensated by adjusting wellbores’ flow rates with respect to each other. This is best done by establishing flow-rate

employed to achieve a parsimonious model of the given data. Note that a parsimonious model in this context refers to one containing the m

ggest that vertical communication through the entire reservoir section achieved through fracturing is a dominant mechanism for improved p

the higher oil saturations as calculated from vertical well logs and better permeability as noted by vertical well log resistivity invasion profile ace fractures with longer fracture half lengths and reduced fracture heights improving the possibility to contain the fracture in the pay zone T

gy has evolved and the scope of relevant well-types has expanded. e reservoir. These factors make it difficult without direct measurement to determine the inherent wettability of reservoir. The fact that the co ; Wolhart et al. 2004). Alternatively more advanced numerical models have been developed for hydraulic fracture simulators (Smith et al. 2 ty to use various mix-water fluid types. Viscoelastic Surfactant Fluid Development. Viscoelastic surfactant (VES) fracturing fluid systems ha ng costs associated with moving water to treatment facilities often make this an expensive option for operators (Kaufman et al. 2008 Horn nge from 0.42 psi/ft in the Upper Williams Fork to 0.56 psi/ft in the lower section known as the Cameo.� Typical fracture gradients range ations. Modern frac-and-packs involving the use of the TSO technique high proppant concentrations and gelled fracturing fluids were first in cess. This paper describes a combined technique to control fracture height growth through the use of selective placement of artificial barrie members from both KOC and the service company worked closely together to recover the resources in these very challenging environments are often interbedded with sandstone lenses. As these reservoirs have been in production for several decades pressure maintenance is low expectations1.

s to stimulate each production interval independently to optimize gas production from each interval. The difficulty is to find a method that is ching of the brittle linear-elastic model with field data by means of the appropriate choice of effective fracture toughness shows that the valu atory Fluid Loss Measurements To model the fluid loss properties the VES system was injected into 12-inch long sandstone cores at a co

ell was the one that was producing naturally.� Poor success of initial fracture-stimulations observed by most operators perhaps contribute

ill be discussed in details in this paper. The planning and execution process of the acid fracturing treatment that was implemented is shown at mitigate the yield stress effects to help restore the effectiveness of the full length of the fracture. In addition it presents the first data char in a highly laminated formation.� Sand layers have contiguous thicknesses of only a few inches up to 15 ft.� Very fine grained sandsto

e the borehole deviation are used not only the to determine fracture azimuth but also the distance between the treatment and monitoring w

statistical properties of the surface-roughness distribution are related to the fracture conductivity. uction development and enhancement activities have started in 2000. The AC-11 formation consists of laminated oil saturated sandstone. T yzing the placement and flow of various processes and materials�. Radioactive tracers have been found to be useful in developing inform

each segment.

lar HCl acid has high leak-off rates that hinder acid propagation during fracturing treatments. The rate of leak-off 3 Ct can be determined us

rtheless the observed seismic radiation can be used to at least constrain the orientation of the fracture plane in cases where the data cann

n. The problem of fluids displacement from porous media instability and viscous fingering was addressed in many papers [3-10]. Investigati n in the wellbore formation elastic properties and fluid loss data. Rueda et al.2 discussed considerations for pushing fracturing limits to max

io sandstone cores (~ 0.2 md) confining the proppant pack a metal cell with a movable top piston for controlling the closure stress pressu

he Carm�polis field were below the expectancy. The low reservoir pressure associated with the high costs of the fracturing operations an ory experiments and was recognized as an important feature.23 27 Numerical modeling of fracture growth resulting in offset development is available nodal analysis packages cannot easily model auto gas lift wells. Interestingly the flow control valve technology developed for au and perforated completion with oriented perforating. Tubing conveyed perforating (TCP) assembly consisted of a gross length of 1 301-ft w lity to effectively stimulate or fracture different intervals of the horizontal wellbore particularly in reservoirs that are not naturally fractured. T ty to effectively stimulate or fracture different intervals of the horizontal wellbore particularly in reservoirs that are not naturally fractured. Th vity index but usually damage due to drilling mud is a concern. During the recent years mud systems evolution was remarkable. The objecti

he field from �5 cP 8 cP 12 cP 19 cP to 21 cP and corresponding API gravities. Figure 1 shows the location of Bloque 15 Ecuador. Ge

imizing the inflow profile along the well using fixed control devices sized prior to installation (e.g. Brekke and Lien 1994; Permadi et al. 199 9. The experiment was designed to perform two tests in one large block. Two conditions for hydraulic fracture propagation were examined:

characterization other frequently asked questions for thinly bedded reservoir are: What is the productivity of a well drilled in this type of r e inclination and orientation in the in-situ stress field and formation strength. lf can be filled with rock and charge debris.� Ignoring the heterogeneity caused by perforations can result in major simplification in unders w perforating technique. Background Well-0 was the discovery well of Field-β. It was drilled as a vertical well and completed with a standa rmeability of 26md followed by water saturation of 37.7%. After 2 years of production gas rates started to decline from 18 MMSCF/D down rforating technology developments have been focused on obtaining deeper penetrations. However few breakthrough advances have been e the thin pay sandstones often have a bottom oil/water contact. Acid stimulation is possible; however the success rate of sandstone acid s 16 and has produced over 1.6 Tcf gas and 53 million barrels liquid from Cretaceous and Jurassic reservoirs. The Cotton Valley reservoirs at ble. Also executing a job with such a high drawdown in these conditions would be dangerous and is not feasible from an operations standpo ure transient that provides an opportunity to evaluate the dynamic formation properties with interpretation methodology of the PTT. A variety sanded in due to higher than expected underbalance Premature firing of guns due to pressure surges. ng system developers. A second application is to special perforating jobs that may require some alterations to an existing perforating system

s pilot program led to a development plan with 16 horizontal producer wells with lateral extensions around 650 m and 14 horizontal injector

ve failed prematurely due to either productivity loss from screen plugging or loss of sand control from screen erosion.� Consequently mo ola fields are located in shallow immature sediments which typically have reactive shales that are incompatible with water based fluids. The

pletion cost an intensive laboratory activity was carried out to identify a chemical solution to prevent the problem related to the exposed sh r pump rates for the same alpha-wave dune height as in conventional gravel7 and drag reducing additives that can be used in the carrier flu

que adopted by many operators in this region. Since most of these reservoirs contain reactive shale streaks they require synthetic/oil-bas

ons. Stand Alone Screen (SAS) solutions are perceived to have a higher risk wrt running to TD hole stability and plugging potential along a to surface. The wormhole dimension was calculated to be greater than a 6 inch equivalent diameter. To date there have been several failu s for these secondary targets have been limited. A screenless completion eliminates the need for screen to prevent sand failure. In addition

examined seven wells in the south eastern part of Sarir. It identified the source and severity of the sand production linking the problem to th can be achieved by focusing effort on certain input data targeting and reducing specific uncertainties and by employing pragmatic models tion for this field is obstructed to a lower level which lead to significant economical loss. A geomechanics and sanding study was initiated i

strength of the reservoir rocks which is directly related to their risk for ure were derived from analysis of openhole logs standard leak-off test data coefficient of active earth pressure and qualitative stress inform ar et al. 1984). The addition of uncross-linked polymers to HCl improved acid penetration; however acid placement did not significantly imp and the fracture conductivity is more dependent on the rock strength than on the initial etching pattern.� The success of the acid fractur ntegrated with the new technology and enhanced methodology which is constantly developing. Although relatively new with the Permian B

ting acid systems were injected through limestone cores suggested that viscoelastic diverting acid systems would provide diversion during he damage created during the drilling or cementing process or damage created by sustained production. Typical wormhole structures can r

vate the overall complex chemistry involved in the sandstone stimulation process.5 Accordingly the need to have a proper tubing pickling pr

c and formic acids are typically used at concentrations less than 13 and 9 wt% respectively to avoid precipitation of calcium acetate and cal

d the treated region eventually becomes the sink for the acid and leaving other regions not adequately acidized.� Therefore one of the m Most of these gas fields are in production since the 80-s and have been significantly depleted with reservoir pressure Pres as low as 12 b teristic dissolution patterns are observed at different injection rates 5 6. These patterns are categorized as face dissolution wormholing an have played a key role in restimulation success during the past ten years as have the technological advances in stimulation fluids and prop m a well drilled and completed in 1993. Accordingly the operator opted to run a dipole sonic imaging tool to have a better estimation of criti

servoir is fully or partially stratified and tectonically screened. The productive horizons are composed of terrigenous rocks the host rocks b

ng the complexity of the operation as well as the production loss from the lower Burgan formation during the workover. Thus an engineering plied selectively however. Only cement barriers between formations where production is planned are tested (Figure 1). Intervals between res p it indicates a time within the shut-in period. The basis of the CCTs lies in the principles of slug tests originally designed for testing water oke followed by a shut-in period to let the reservoir return to its initial pressure Initial 8-hour flow period on 24/64 choke to perform flowing s on methodology is reported in the paper that permits the quantification of the well and reservoir in situ properties on a layer-by-layer zone-b

th drawdown and buildup tests. Several numerical examples are included to illustrate the step-by-step application of the proposed techniqu ls in nonhomogeneous and heterogeneous formations and reservoirs. Nevertheless understanding the fundamental radial flow regime is e nformation based on few scattered measurements is propagated to make important decisions.� In case of production engineers the con ective could be achieved with some success then as stated by Levitan the deconvolved response would remove the constraints of conven

han doing the traditional deliverability calculation with four points. Then he uses these parameters to predict future deliverability by forward s of equipment. The Abu Al Bukhoosh oil field is located 80 km offshore Abu Dhabi. It is a large NE-SW anticline affected by NW-SE trendin emote unmanned operations Lowering of risk associated with well testing in gas well operations through elimination of active control system

an the traditional separation approach. It is not surprising that the use of multiphase flowmeters has grown significantly the worldwide num

gh energy gamma ray being already present for density measurement the addition of a second radionuclide or an appropriate chemical sou block size. The authors recognized that well tests would not fully cover the full field model. Therefore they found it useful to calculate proper

we describe a new technique for differentiating well test pressure data called the digital pressure derivative technique (DPDT). The DPDT pr inflow to each zone (Fig. 2). The 21 centralizers acted as electrodes to form an electrode array that spanned the 694-ft-long completion. Ea

ted but cannot easily be controlled; others (such as fluid loss) can hardly be predicted at all. In any case they belong to the class of fault-fre dependent components of the stress tensor at a point and so procedures for in-situ stress estimation at depth must combine complementa

enhanced oil recovery but also for long-term storage. -injection study for a CO2 injection illustrate aspects that are needed for designing monitoring and injection strategies. Injection of CO2 in S

es from coal deposits leaking natural gas pipelines landfills forest fires wetlands rice growing and cattle rising. Nitrous oxide also know in achieving a successful storage project. In particular seal integrity must not be impaired by the mechanical effects of storage operations.

er zones hence adding value to the DIACS completion design Experiences from this well show that even longer wells can be drilled from

orkers on these structures during this time was Gill (1973 1975 1977 and 1979). In 1987 Cercone and Lohmann discussed diagenesis in t rmore high CO2 concentrations are encountered in diverse areas. The scientific study of natural CO2 deposits is still at an early phase. Pr een success at much lower porosity in the range of 8-10%.[3] Obviously if a 16% porosity cutoff was applied routinely then somewhere in ural depletion without considering any pressure maintenance.� The simulation model and parameters are described as follows.

petrophysics characteristics of altered basement rocks in the White Tiger (Bach Ho) field change very strongly both with depth and area. Pe sired treatment is pumped the packer is either deflated and retrieved or the running tools are disconnected from the TTIP and the coiled tu essfully carried out this operation in four wells drilled and completed in Field X. The biggest issue associated with cement squeeze in a sing

er in the form of gas injection from surface or downhole commingled gas from another zone. A PC-SAFT equation-of-state (EOS)2 3 based ristics are caused mainly by the large momentum-transfer capacity small buoyancy effects lower free energy at the interface and smaller ow is based on the balance between the turbulent energy of the continuous phase and the surface free energy of the dispersed phase. The for production.�The application of intelligent completions for such commingling wells allows not only the production and recovery optimi neering expertise developed and implemented a workflow to put together a single integrated well-network-process simulation model and u s of very different densities are mixed. For example a problem may occur when a condensate is mixed with black oil. The density of the ent on in the measured flow assurance properties of a waxy crude oil at actual field conditions and at stock tank conditions. In particular the im tress associated with drilling completing and producing wells such corrosion can cause catastrophic failures of the downhole completions pH6 to monitor the cleaning-up process using downhole pH when sampling formation water in a well drilled with WBM7

procedure for gas condensate fluids. Coats procedure was extended by McVay4 for volatile oil fluids. Walsh and Towler5 also presented a

pay zones which can contain significant amount of hydrocarbons. Also the well known density-neutron separation may not always result in from pressure gradients based on so-called database regardless how much uncertainties of ‘fitted’ pressure gradients can contain. B

ongly on adequate characterization of the physical and chemical properties of the fluids. In many deepwater and other high cost wells wireli

OBM. A focused sampling device is introduced to overcome this challenge by isolating small amount of filtrate that can mix with sampling lin of exploration appraisal development production and abandonment of a given prospect. Indicate the need for special metallurgical or p

avitational potential gradients. Temperature gradients can also contribute to concentration variation. In light oils with gravity greater than 35

ations. It is much more preferable to perform the sample analysis in situ so that the subsequent sampling program can be optimized in real t

pressure and temperature ranges of 350-400 bars and 80-100C are close to critical temperature of mixtures of hydrocarbons in several se using a technique of monitoring OBM contamination which is based on measuring the change of methane content and color in the flowline

This is also not only limited to reservoirs containing gas condensates or volatile oils but is observed in heavy oil reservoirs as well (Mullins in the tool flowline. Fluid from the formation flows through a probe into a flowline positioned in a tool in the wellbore and is assayed by a do es use the absorption spectroscopy of reservoir fluids in the visible to near-infrared (NIR) region. On the basis of their molecular structure d

acterized as non-condensable then a gas phase will always be present which contains these components. . 2002). In addition to formation blockage and general difficulty in the separation of oil and water in production facilities one of the main dra

to the economics of field development. Chemical analysis of formation or connate water determines the scaling and corrosion potential of p e not completely full but clean. This may be adopted as a standard best practice and is applicable to any Wireline gas-condensate samplin 3]). A MFM could be located anywhere from the well head flowing temperature and pressure up to separator conditions or lower. Figure 1 pletion caused by intense production or simply due to the imbalance between low productivity and production requirements. The experience

ervoirs of deltaic origin) is not an exception (Table 1) and shares the need for a thorough preparation to execute any matrix acidizing treatm n migratory fines (typically aluminosilicate fines) or inorganic scales. Concentration) requires high dosage in continuous injection applications. When the same chemistry is used in squeeze applications the sq

re flow efficiency (CFE) of each sample is calculated. e size results in the damaged zone having a permeability much decreased from that of undamaged rock Pucknell & Behrmann[1].�Add ce of the injection water that is used for the water flooding. The technological production processes that are prevalent in the local industry sh task of predicting the treatment-life of an inhibitor squeeze is difficult in a multi-layered commingled system due to commingling of different

s of UZ formation water and injected seawater at reservoir conditions is 0.57 for strontium sulfate which is only just above the positive thresh ¿½It is the results of that review process that are presented in this paper. Reservoir Description and Field Development Gyda hydrocarb ints of maximum uncertainty from a flow perspective and also the number points should be kept as low as possible to decrease prohibitively

ed in demonstrable productivity increases wherever the technology is properly positioned and utilized.

illustrate this achievement with the example of Activo Integral Burgos (AIB) the oldest and largest onshore gas-producing basin in Mexico in the southern part of the field. (Ref 2)

PCP system was evaluated for the production of extra-heavy oils. A discussion of the applicability of this artificial lift method and a compariso

the matter will be placed in (Datta and Anantheswaran 2001).

ence right lateral movement in the Cretaceous. All the basins of the Sudanese rift-related system such as the Muglad White Nile Blue Nil and a gross thickness of about 750 feet.1 A structure map is given in Fig. 2 ela basin 1. Understanding the nature of reservoir fluids is essential for the optimization of completion facilities design and reservoir produ

movement and several sub-basins formed result in this large numbers of tensional faults. Structures within these depressions show signific

an 10%. Introduction The Nukhul formation is a depleted fractured dolomite reservoir producing 9 to10 API heavy oil with water cuts up to

hods were suggested to retard the traditional mud acids including the use of buffered-HF systems 8 fluoroboric acid9 and mixtures of esters

eenout. (Nolte 1988 Walser 1988 Almond 1984) Gelling at varying temperatures can be achieved by delivering a crosslinker that has two (

m reservoir engineering considerations. Hydraulic fracturing has been found to be the most effective technique to bypass skin-damage in the stone acidizing and sustained production increase from high temperature sandstone reservoirs. A comprehensive laboratory study which e complexity of the treatment. An alternative approach uses chelating agents combined with acids as the main treatment agent. Chelating s of continental origin covering several formations whose names depend on the geographical area (see Fig. 2). The lithology changes from ance water removal is to increase the volume displaced in the initial stage by decreasing the capillary pressure of the formation. The reduc mation about compartments and communication in the reservoir. Later in the production cycle these data can be used to differentiate produ

creased percentage of gas being tight gas it has become more challenging to produce especially as production moves to more remote are

mon that the ongoing water injection program is above the fracturing pressure hence water injector wells under intensive and long injection

2 injector wells (2 in B4 and 1 in B7).

uccessfully completed in the low permeability Ratawi Oolite reservoir in the SF field. Well test data showed production stabilized at 914 BOP in the Greater Green River and Piceance Basins their static and dynamic modeling workflows and a comparison of the models’ and a aramide north-trending San Rafael and northwest-trending Uncompahgre uplifts.� The basin is an asymmetrical syncline with the deepes ation and rock compaction. The reservoirs are overpressured with a pressure gradient of approximately 0.7 psi/ft. To honor the pressure gra net height of laminated sand evaluated is compared with post-frac well production data to determine if the additional perforated intervals and

o simultaneously characterize extreme rock and fluid complexities with sufficiently high resolutions so as to greatly aid in reservoir evaluation

than optimal surface kit footprint partial-depletion related completion problems potential over-capitalization and overall systemic inefficien

hus reducing the pressure in the flowline. ����������������b. Once pressure drops below sand lectrosumergible pumps (ESPs)] to take advantage of the enhanced productivity. The main purpose of the hydraulic fracturing was not only

netheless technical capabilities of exploration at that time did not give the opportunity to meet the challenge of prospecting and exploration

isions about where or even whether to drill a production well need to be rapidly made an efficient reliable method of diagnosing the transit

ew oil discoveries too. Most important is continuous reduction of lifting cost by introducing new technologies. These technologies have redu

e the geometry of reservoir and non-reservoir bodies. This framework is fundamental for creating a static model. Both core and log measure ements can be divided into two categories: static and dynamic. sation fractures or stylolites for instance. However reservoir engineers do not always see the purpose of integrating such high resolution to

nt fluid analyses. However the amount of filtrate contamination can be reduced substantially by use of focused-sampling cleanup introduce t is common to have low resistivity pay zones which can contain significant amount of hydrocarbons.� Also the well known density-neutro e later stage of field development.

for formation evaluation. We will discuss here the application of the rich data set produced by this tool for the evaluation of lithology and min

ainty in the input parameters for the different shaly sand models will complicate the interpretation for a specific shaly sand formation as usin ameters for the different shaly sand models will complicate the interpretation for a specific shaly sand formation as using improper model th able core data. These checks will be described for each step. Both routine core analysis (RCAL) data such as porosity permeability and gra type classification using the artificial neural net technique was successful in replicating rock classification. An average quantitative resistivit are developed in some intervals.� The other common texture is that of sucrosic dolomite of varying crystal size. Due to this geologic com ools. In addition the use of images and wireline formation testing from the example well provides the appropriate benchmark for improving

e show how to use NMR to verify these two outputs. The third verification is the sand porosity computation. Finally the fourth and last verifi

Azzouguen et al 2000). er tool or damage the pump modules. We will treat each of these aspects individually in the sections which follow. some fractures that are occasionally seen in cores (i.e. core discing) are not seen by images logs. Such fractures are artificial in origin ca the Tayarat Formation reservoir units. An attempt has been made to explore this petroleum system using the newly acquired 3D seismic w

make them the tools of choice for reservoir modeling. Such techniques are especially useful to characterize geologic facies object size pe s describe the workflow and the details of the analysis. stijn’s 1982 paper1. The second is the use of shallow measurements with intrinsic high vertical resolution to enhance the deeper measu

onditions demonstrate the importance of reservoir conditions that in some cases may be manipulated to enhance oil production. Based on t stresses. In addition drilling through highly pressure-depleted reservoirs raises considerable risks of excessive mud loss internal blowout

sts of a complex fractured vuggy-porous type of a reservoir. A presence of opened fractures was determined as a key factor that defines pr

uggy-porous type of a reservoir. A presence of opened fractures was determined as a key factor that defines productive potential of wells.

may then be mobilized and can cause near wellbore formation damage. iv. Plugging by particulates particularly fluid loss control additives

ition concurrently with thin shale-silt laminations over certain intervals. In these formations the petrophysical analysis is affected by strong l utilize NMR data. Hydrocarbon type is usually inferred from well logs or from prior field knowledge. Sometimes large density-neutron separ

meters and noise."

ir can be obtained. Productive reservoir zones and formation properties can be determined provided there is proper flow monitoring at the aces (time lines at field scale). There are two major sequence boundaries with exposure time one at the top of the underlying Rumaila Form

proportion of methane (C1) ethane to propane (C2-5) the hexane plus fraction (C6+) and carbon dioxide (CO2). The gas-oil-ratio (GOR) o luid as close as possible to that in the formation minimizing as much as possible the risk of undesirable phase transitions. Wireline-convey

mobility-ratio of oil and water phases (0.47) and generally homogeneous thick reservoir sequences indicate oil is swept by a favorable gra een discussed for such environments (Ferment et al. 2004) highlighting issues with high differentials probe plugging fine laminations and

agement. During the WFT survey the dual packer and single probe combination also enabled us to conduct interval pressure transient tes upercharging effect is not profound. Background During or immediately after drilling pressure near the wellbore is influenced by mud filtrat ocedure is required which generally converges after several iterations. Converging to an optimized field plan involves identifying the best su mic technology and stratigraphical correlation across wells is very difficult. In this context the use of wireline pressure tests for reservoir cha

lock general stratigraphy and the reservoir management structure put in place by PESA. For the sake of completeness a generalized strat ficial lift due to low reservoir pressures prevailing fluid properties and continuously increasing water cut."

mize well placement drilling completion and workover intervention for such cases1 2 3 4. Artificial lift maybe used to improve the performan

vailable possibilities for advanced FM users. The paper is presented in the following sequence: the big picture depicting the FM framewor that the engineer can make an adjustment from the office and receive quick feedback on the result. a strong aquifer drive throughout the Betty field aquifer energy provided to the reservoirs combined with the favourable mobility ratio resulte

ed by the surface model in the reservoir. hat has never been seen before in the Oil & Gas industry will need to be established if suggested improvements such as $30mn per year eering expertise developed and implemented a workflow to put together a single integrated well-network-process simulation model and us uncertainty reduction in deterministic workflows is a trial-and-error exercise that is subjective and open to varying interpretations.� This is s making water control difficult to achieve. ESPs are used in all wells of the field to improve productivity. Typical well production rates are o

st priority among various alternatives. In addition the poor petrophysical properties of shaly layers did not effectively produce oil from vertic ute the baseline to maximize the subsequent hydraulic fracture design and the resulting overall well deliverability. Thus we narrate a proce very. Well histories are quite complicated due to the workovers (add or squeeze perforations refracs commingling etc.). Fig. 2 shows a typ

ns such as in thick resistive beds measurements are able to detect conductive boundaries at distances greater than 15ft.1 The technology ld development plan based on an integrated reservoir model utilizing all well and test data with a sophisticated geophysical model derived ¿½ï¿½ï¿½ One activity is the task of reservoir modeling which has a rich toolbox of methods and techniques.�Nowadays even during t esolution quartz gauge was positioned on the exterior of the tubing string and exposed to wellbore pressure by a port; then it was connecte rget of the Approach Most of the fields in the world are water flooded.� Thus mature water flooded fields cover the highest percentage o Decision and risk analysis completes the full cycle of reservoir engineering well placement and well completion has been rigorously evaluat guration (Ramirez 1987 Asheim 1988 Sudaryanto and Yortsos 2001 Zakirov et al. 1996 Virnovsky 1991 Brouwer and Jansen 2004 Sarm

cy of analytical models is generally judged by accuracy and speed. or well testing applications for many years (Gringarten and Ramey7 Cinco-Ley et al.8 Raghavan9 Al-Khalifah et al.10 Gomes and Reza1 uction history and comparison between the two approaches can be found in the literature.12 13 Unlike the deterministic approach the Baye

manner that geostatistical parameters are consistent in the final history matched model."

n and composition constraint equations. For thermal models where water component could reside in the gas phase the total number of va

es and proper production logging methods for various horizontal well conditions are discussed in the literature4 5 6 7.� Once a problem is

problem such as shutting off the high water or gas entry perforations5 6.

reservoir-matrix permeability can cause mechanical damage through various mechanisms including fluid invasion into the reservoir polym hydraulic fracturing treatments the intent being that the polymer will be recovered once production is initiated. In the field only a fraction o s confirmed that contribution is dominated by dolomite section (zone 1). The result of this can lead to inefficient reservoir sweep and reduce used in�� papers2 3-6� and allowed to account of various phenomenon taking place under gas condensate flow in vicinity of the hy his paper we present a fracture height growth model that takes into account the bedding plane interfacial slip. The model has been implem simplistic methods because the vertical communication caused by fractures is not properly modelled.� In recent years numerical simu

cture half-length fracture conductivity and drainage area. However instead of using a rigorous flow model he states that it is often difficult stivity theory for computing the dimensionless productivity index of a vertically fractured well with an arbitrary fracture conductivity distributio deed the flow source is assumed to be a line of either fixed (PKN) or increasing (KGD and Radial) length with orthogonal flow along the fra ure and may result in early screenout. Pinching can be caused by a number of factors. produce an ANN with better error performance or other qualities giving the so-called “ensemble learning methods a term that covers a

n since some reservoirs have no representative fluid samples for a complete PVT analysis and correlations are used instead for material ba

e can be either without a porous medium or filled with a porous medium. The thermal diffusion in a binary mixture causes one component t

tipoint flux transmissibility coefficients as an adjustment to standard two-point flux transmissibilities and the method of constructing an M-ma

r elasticity equations under given boundary conditions and simultaneously calculates the corresponding stress/strain tensor fields (Bourne

saturation transport along streamlines. This work is devoted to an efficient implicit numerical solution of the saturation transport along strea either as volumetric grid cells or as lower-dimensional objects at the cell faces. The performance of current finite-difference simulators can

on for 16.5 years of total production and characterize the uncertainty in this prediction.

u scale precipitation is conducted using the FrontSim reservoir simulation software (FrontSim 2008) which includes a specialised brine com

ntal method (e.g. IMPES [11]). The goal is to use the least possible number of pressure updates in order to maintain the required accuracy.

ns using data mining methodology. The objective of this paper is to present the methodology and results obtained during the analysis pha

ey describe the patterns in the data. These parameters can then be used for subsequent analysis. Description of method The proposed a simulator (Schlumberger 2008a 2008b). In the previous formulation of the model each segment could have only one outlet. This restriction

rbon fluids are generally at near-critical conditions. Figure 2-a shows a typical PVT diagram from one PVT sample in Marrat. The reservoir t

eynolds number V/μ (also called the Forchheimer graph). The apparent permeability kapp is defined as ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿ ast reservoirs of the behavior to be�typically expected from open hole pressure surveys which have been performed in such zones and duce risks and the costs associated with a new well or having to pull existing tubing. The equipment and methods to drill successfully have b active region involving multiple faults and variable degree of displacement of the adjoining structures.� While mentioning a stress map w ted by the readership.1 2 OperatorTerminology BP“Field of the Future Chevron“i-field Shell“Smart Fields Also during the

ovince corresponds to the portions of Chukchi shelf and Beaufort shelf and the onshore Arctic Slope as shown in Figure 1. The Arctic Slop for the latter) depending on the expected failure mechanism. In general decreasing the Young’s modulus or increasing the Poisson’

monitoring: through-casing resistivity pulsed neutron capture and neutron inelastic capture measurements. Aulia et al. (2001) provide a co nd lateral bore with flow measurement of the main bore. Applied downhole two-phase flow and density measurement principles were the sa 2.5-15 cp. Uncertainties of the fluid type were eliminated with the extensive zonal sampling in the field. The PVT data illustrates that the oil h fficult once water breakthrough occurs.� Array holdup tools of capacitance optical and resistance type have been available for some tim

����������� Minimize time on station such that rig costs and the probability of tool sticking are reduced.

t module and sample chambers. At the start of the sampling process fluids flowing from the formation are largely contaminated with drilling oduct skin and current reservoir pressure. This type of system and workflow has been proven valuable in identifying wells as candidates fo ranging between 30 to 100 ft in length. The well casing in these intervals was perforated and sealed off by packers from previously perforat o success is in applying multiple techniques that can help validate a particular observation from different vantage points. The case in point i

m continued through 2005. he entrained liquid droplets upward in the flow stream.� As noted by Turner et al3 as well as from field observations of wellbore liquid unl he flow stream. As noted by Turner et al3 as well as from field observations of wellbore liquid unloading conditions4-11 that the criteria for by providing large data sets to properly identify transient temperature behavior. The natural extension of permanently installed DTS system

e in such a way that a performance monitoring closed loop can be established. As indicated by Othman et al1 with the production incremen

.� The formation of wax crystals depends significantly on temperature change. Pressure and composition also affect their formation but n tone. Mostly it is medium-grain sized crystalline fractured and vuggy cquisition objectives is essential for success. Figs. 1 and 2 schematically illustrate the real-time monitoring concept. Real-time data are view emperature system (DTS). During early production a near-wellbore reservoir model is characterized to match the well-bore temperature pro . The combined monitoring also can track fluid movements in the reservoir allowing optimum well and pattern design and subsequent opera opment strategy of the Azeri field requires a good understanding of the production and injection conformance both geographically as well a total production compared with equivalent dry-tree installations and most have less data (Selim 2003). Hence there was a crucial need fo

overcome these limitations. To do so a production volume estimation solution should address the following needs of the Oil & Gas Compan ee of reliability in these oftentimes hostile environments. This paper examines an alternative flow detection solution and provides recomme

he years and numerous patents and articles have been published. Nuclear emission based techniques were the forerunners in this categor

ateral sweep due to reservoir complexity. Detailed simulation modeling was performed to delineate optimum strategy for maximizing reserve of more advanced (deep reading) methods. Selected well-based monitoring methods include well logs and pressure and flow data. Evaluat erta alone is predicted to have 500 Tcf of CBM to be developed equivalent to 83 billion barrels of oil. Approximately another 2 500 CBM well et. al. 1994) The degrees of cleating nature of cleat network and relative connectivity of the cleat system varies from one coal seam to thos e susceptible to fluid invasion damage. In addition the very soft nature of coal means that these fracture systems can be closed down due ormance was not increased drastically with slickwater completion costs were reduced by approximately 65%. In 2002 horizontal wells were t its entry point with the wellbore. In brittle high modulus formations high fracturing initiation and treating pressures generally result from loc

remely large fracture surface area that can be economically generated. The stimulation cost reductions allowed Mitchell to complete the Up pattern) designs various well spacing pilots (e.g. 500 ft 1 000�ft and 1 500 ft etc.) were drilled and various hydraulic fracturing operatio

ck organic-rich shale with ultralow permeability in the range of 70 to 500 nanodarcy. To attain economically viable production rates hydrauli acidizing on the other hand the chemistry of acid-carbonate dissolution is straight forward especially for the HCl-carbonate reactions. The a

he subsequent calculations the primary concern here is the flowrate and not the pressure. Nominal pressures are required but very high flo reservoirs are associated with the delta tributaries and crevasse splays while the BS reservoirs consist of coastal-deltaic sediments and cr

fficient treatment of individual layers in cemented casehole completions. TAP Completions use special casing valves that isolate individual l

echanisms that must be considered in evaluating the transport capability of a system for moving liquids upward in the well.�� These a echanisms that must be considered in evaluating the transport capability of a system for moving liquids upward in the well.�� These a and sedimentological analysis; and geo-mechanical modeling.

best done by establishing flow-rate control through variable completions. Thus for areal nonuniformity and heterogeneity we expect a rese

ontext refers to one containing the minimum number of significant parameters that adequately represents the data. Finally we conclude tha

dominant mechanism for improved production performance. Connecting the stimulated wells in the full field model (FFM) to all grid cells abo

al well log resistivity invasion profiles.�� Higher production and reserves of these wells reflect these higher oil saturations in the Middle ontain the fracture in the pay zone This proved to be beneficial particularly in reservoir conditions where fracture vertical extension barriers

lity of reservoir. The fact that the composition and surface of the reservoir are heterogeneous in three dimensions further complicates the a ulic fracture simulators (Smith et al. 2001; Siebrits et al. 2001) and the combined effect of height-containment mechanisms can now be stud ant (VES) fracturing fluid systems have been routinely and successfully employed over the last two decades in hydraulic fracturing applicati erators (Kaufman et al. 2008 Horn 2009). Literature has also been documented on the use of untreated recycled waters in high rate low p ¿½ Typical fracture gradients range from 0.5 psi/ft to 0.75 psi/ft and Young’s Moduli range from 3-7 million psi. nd gelled fracturing fluids were first introduced in Venezuela by Schlumberger in 1996. Since then this technique has become the preferred elective placement of artificial barriers to proppant transport that are placed adjacent to the pay zone adjusted frac fluid systems and pump hese very challenging environments through the use of the latest openhole stimulation technologies available in the market today. An innova al decades pressure maintenance is normally carried out with water injection. The produced oil has a low GOR hence there is no gas injec

he difficulty is to find a method that is efficient effective and cost competitive. The sequential opening of a single productive layer and isola cture toughness shows that the value of the fracture toughness measured in the laboratory can be by order of magnitude less than the in-sit 2-inch long sandstone cores at a constant driving pressure of 1000 psi. The cumulative fluid volume flowing into the core was measured a

y most operators perhaps contributed to this belief.� Other completion “principles which may owe their origin to either hearsay or exp

ment that was implemented is shown in Fig. 1. The detailed steps within this process are listed in Table 1. ddition it presents the first data characterizing flow across the filter cake to simulate flow from the reservoir into the fracture as opposed to c o 15 ft.� Very fine grained sandstones siltstones shales and limestones comprise the majority of the rock types found in the Cotton Vall

ween the treatment and monitoring wells. Traditionally in HFM the initial isotropic velocity model is built from sonic logs and/or vertical seism

aminated oil saturated sandstone. The average permeability of AC-11 formation is 8mD and the porosity is 13-16%. The average oil satura und to be useful in developing information in virtually all aspects of drilling completing and producing a well. A particularly popular use of ra

f leak-off 3 Ct can be determined using Eq. 1

plane in cases where the data cannot image the failure-plane orientation accurately. In this paper we present a case study by use of micro

ed in many papers [3-10]. Investigating instability in miscible displacement differs greatly from that in immiscible fluids. The presence of a sm s for pushing fracturing limits to maximize productivity. They derived optimum fracture length width and conductivity as a function of reservo

controlling the closure stress pressure and temperature ports and inlet and outlet ports with valves.�The cores are cut to shape and pott

costs of the fracturing operations and the low oil prices turned these operations uneconomical during the nineties. After 2000 the increase wth resulting in offset development is not often undertaken. Jeffrey et al.13 considered offset development as a result of sliding on the natura l valve technology developed for auto gas lift has found applications in subsea and deepwater wells using conventional gas lift. The reason sisted of a gross length of 1 301-ft with a net perforation length of 460-ft 4-spf and 180o phased 4-1/2-in guns and a packer. The guns were rs that are not naturally fractured. The use of limited entry and bullheading techniques provides little if any benefit compared to vertical we s that are not naturally fractured. The use of limited entry and bullheading techniques provides little if any benefit compared to vertical wel olution was remarkable. The objectives are to achieve: Very low leakoff to the reservoir by the design of optimized filtercake this will preve

location of Bloque 15 Ecuador. Geologically the Oriente Basin of Ecuador� is part of the upper Amazon River drainage system and cov

e and Lien 1994; Permadi et al. 1997). Active control is facilitated by the adjustable inflow control valves (ICVs) installed in intelligent wells. acture propagation were examined: �������� i.����������� Fracture #1 extending throu

ctivity of a well drilled in this type of reservoir? What is the connectivity between wells drilled in this type of reservoir? Answers of these qu

esult in major simplification in understanding how carbonate acidizing works in real wells. In a cased-hole completion perforations provide t al well and completed with a standard completion including a 3.5-in. production tubing and a 7-in. packer. Well-0 was perforated in static un to decline from 18 MMSCF/D down to 7 MMSCF/D with gradual increase in water gas ratio up to 10 BBL/MMSCF. This phenomenon was a breakthrough advances have been achieved relating to tunnel quality. The industry has relied solely on static underbalance which is now a he success rate of sandstone acid stimulation is low. All perforation creates a low-permeability crushed zone in the formation around the per oirs. The Cotton Valley reservoirs at Bethany consist of multiple tight gas sands mostly blanket in nature from approximately 8 000 ft to 10 feasible from an operations standpoint. Also after the first run shot with a static underbalance the well will be at balance conditions so any s n methodology of the PTT. A variety of technologies such as slug test (Ramey et al. 1972) closed chamber test (Alexander 1977) surge t

ons to an existing perforating system in order to meet a specific technical requirement. If the job is imminent with little time for engineers to

und 650 m and 14 horizontal injector wells with lateral extensions ranging from 650 m to 800 m. Further analysis added one producer and o

reen erosion.� Consequently most of the operators have accepted gravel packing as the sand control means5. mpatible with water based fluids. The experiences from the analogue fields in the basin clearly demonstrate the reactivity of the shales. The

e problem related to the exposed shales. es that can be used in the carrier fluid either throughout the treatment or during the Beta Wave.8

reaks they require synthetic/oil-based drilling fluids (S/OB). Considering that a large majority of the openhole gravel packing experience in

bility and plugging potential along a well path crossing significant intrareservoir shale packages. For Open Hole Gravel Pack (OHGP) compl o date there have been several failures in the field with similar characteristics where biocide tracer confirmed the direct communication betw n to prevent sand failure. In addition it can be done rigless. The technique consists of the following key steps: Optimum perforation phasin

production linking the problem to the occurrence of thin beds and proposed new completion solutions to address the issue and optimize p nd by employing pragmatic models that do not rely on over-complicated measurements and analyses. Introduction The giant Messla field cs and sanding study was initiated in the year 2004 to investigate sanding mechanism and to provide the contingency plan to properly addr

ressure and qualitative stress information relating to the in-situ stress regime. The properties of drilling fluid-shale interactions were derived d placement did not significantly improve (Yeager and Shuchart 1997). Crosslinked acids were introduced in the mid 70’s as was cited b ¿½ The success of the acid fracturing process depends highly on the resulting fracture conductivity which is very difficult to predict becaus gh relatively new with the Permian Basin timeline completions in the Strawn formation in Terrell County have endured just such an evolution

stems would provide diversion during the stimulating of limestone reservoirs. Based on this it was decided to apply this system in Tengiz fie n. Typical wormhole structures can range from face dissolution to highly branched ramified wormholes at low- and high-injection rates res

d to have a proper tubing pickling procedure with proper pickling acid fluid had been repeatedly emphasized. Recent marked effort in this re

cipitation of calcium acetate and calcium formate 5 (2) Organic acids have a low dissociation constant. They normally do not react to their f

acidized.� Therefore one of the most important factors affecting the success or failure of a matrix acid treatment is the correct downhole rvoir pressure Pres as low as 12 bar. Conventional stimulation techniques including matrix acidizing using hydrochloric and mud acid syst as face dissolution wormholing and uniform dissolution patterns depending on their shape and speed of propagation.� By increasing th ances in stimulation fluids and proppants. This paper will focus on the common attributes shared by known successful restimulation candid ol to have a better estimation of critical rock mechanics properties like Young’s Modulus Poisson’s Ratio and “in-situ stress. An terrigenous rocks the host rocks being porous. Open porosity in the host rocks accounts for 14–19% and permeability equals 15–60

the workover. Thus an engineering solution of stimulating oil bearing intervals but avoiding suspected water breakthough intervals with the ted (Figure 1). Intervals between reservoirs not planned for production are not tested. Since the majority of cement squeeze decisions are originally designed for testing water wells. Ferris and Knowles1 were the early investigators who tried to extract transmissibility to water from on 24/64 choke to perform flowing surveys and attempt to take a bottom hole sample followed by a 2.5-day initial build-up to get a first estim operties on a layer-by-layer zone-by-zone or frac stage-by-stage basis by evaluating the drawdown production performance of the well in

application of the proposed technique. Introduction Over the last four decades naturally fractured reservoirs have been a topic of continuo fundamental radial flow regime is essential to interpreting pressure transient testing and its radius of investigation; i.e. how much reservoir ase of production engineers the continuous degradation in inflow due to skin affects their return on investment.� For operations engineer ld remove the constraints of conventional analysis techniques (Earlougher 1977; Bourdet 2002) that have been built around the idea of app

dict future deliverability by forward simulations with an analytic tool. anticline affected by NW-SE trending faults which straddles the border between the United Arab Emirates and Iran. Currently on Total AB h elimination of active control systems and reduction of the volumes of pressurized hydrocarbons contained in the testing systems Perman

wn significantly the worldwide number doubling in little over a 2-year period (Mehdizadeh et al. 2002). Multiphase-flowmeter interpretation

clide or an appropriate chemical source could provide the two energy levels required to do the fraction measurement [Ref 2]. This leads to a ey found it useful to calculate property multipliers around each well and then interpolate multipliers to untested areas in the reservoir.

ve technique (DPDT). The DPDT produces the most accurate and representative dp/dt curve by incorporating knowledge of both reservoir nned the 694-ft-long completion. Each electrode was connected to a single conductor that was linked to the surface acquisition unit so that

e they belong to the class of fault-free risk sometimes called residual risk: events causing sub-standard system performance that cannot be depth must combine complementary datasets.

tion strategies. Injection of CO2 in Saline Aquifers ‘Saline aquifer’ is understood here as a brine reservoir or geological formation wi

attle rising. Nitrous oxide also known as “laughing gas is third and arises from agricultural practices fuel burning and industrial proces anical effects of storage operations. Indeed rocks and faults permeability may drastically increase as they undergo stress changes and def

ven longer wells can be drilled from subsea locations in the near future. Optimal pre-planning with use of all service companies involved in

Lohmann discussed diagenesis in these reefs. deposits is still at an early phase. Previous work has included documentation of worldwide occurrences of natural CO2 deposits and prelimi pplied routinely then somewhere in the thousands of wells drilled some pay has been bypassed. One solution that has been used prima rs are described as follows.

rongly both with depth and area. Permeability ranges from less than 1mD to hundreds mD. Two principal porosity types that are fractured/m cted from the TTIP and the coiled tubing string is pulled out of the well. HPHT TTI packers enables permanent abandonment of zones in ad iated with cement squeeze in a singlestring multizone completion is the difficulty associated with placement and confirming where the TOC

T equation-of-state (EOS)2 3 based mathematical model was developed using the published information and the modeling results are prese energy at the interface and smaller dispersed-phase droplet size in liquid/liquid flows (Trallero et al. 1997). Therefore the characteristics of energy of the dispersed phase. The inversion point and effective viscosity of the dispersion are estimated using the Brinkman model (1952) the production and recovery optimization for each individual reservoir but also the value maximization of the well.�Intelligent completion ork-process simulation model and used it to identify and implement several cost effective production optimization opportunities of San Manu with black oil. The density of the entire liquid phase decreases the crude oil solubility parameter decreases and the asphaltenes aggregate tank conditions. In particular the impact of using live versus stock tank oil measurements in the design and operation of the subsea system ailures of the downhole completions or the surface facilities. Carbon dioxide itself is a weakly acidic gas and must first hydrate to carbonic a illed with WBM7

Walsh and Towler5 also presented a procedure to calculate MBO PVT properties from the CVD experiment data. Abdel Fattah et al.6 showe

separation may not always result in water free hydrocarbon production. Coupled with reservoir and fluid complexities above often zones wi ™ pressure gradients can contain. Beside uncertainties of pressure gradients two hydrocarbons can easily have very similar in-situ densiti

ater and other high cost wells wireline formation tester (WFT) fluid samples may be the only source of fluid properties reliable enough for e

filtrate that can mix with sampling line. Lab results of the first field example demonstrated that these objectives were achieved. e need for special metallurgical or process design to deal with certain levels of H2S in the presence of various other mitigating or accentuat

ght oils with gravity greater than 35 degrees API strong compositional grading will often occur where the reservoir fluid is near its critical po

g program can be optimized in real time by comparing observations to predictions. Visible-to-near-infrared (VIS/NIR) absorption spectrosco

xtures of hydrocarbons in several settings. Near critical fluids are then encountered and their description and volumetric behavior is comple ane content and color in the flowline as cleanup with the downhole pump proceeds and progressively larger fractions of formation fluid repla

heavy oil reservoirs as well (Mullins et al 2005 Mullins et al 2007). the wellbore and is assayed by a downhole spectrometer that measures OD as a function of time and wavelength. At any time instant the m e basis of their molecular structure different types of hydrocarbons have vibration absorptions at different wavelengths and a simplified hyd

duction facilities one of the main drawbacks of emulsion formation is an increase in the apparent viscosity of the oil. Viscosity of water-in-oi

e scaling and corrosion potential of produced fluid required for the design of completion and processing facilities (Raghuraman et al. 2007). ny Wireline gas-condensate sampling operation that applies a similar setup and principle. arator conditions or lower. Figure 1 illustrates this. As said previously MFM's request PVT information for conversion this is unavoidable a uction requirements. The experience of northern Siberia has shown that despite that fact significant gas production could be maintained. At

execute any matrix acidizing treatment. Because of the low amount of quartz the first concern for a proper design is to avoid an aggressive

used in squeeze applications the squeeze life is often short due to the high MIC and the poor retention characteristics of the inhibitors. To a

ck Pucknell & Behrmann[1].�Additionally the damaged zone is partially deconsolidated: its strength is much less than undamaged rock. are prevalent in the local industry should not be neglected in the process of scale forming. The conclusion is further confirmed by thousand em due to commingling of different water types and the challenges involved in the predictability of water production. This paper presents th

is only just above the positive threshold SI of +0.40 for the lowest zone of scale risk to the production problems. This would tend to indicate Field Development Gyda hydrocarbon reserves are contained in Upper Jurassic shallow marine sands.�Reservoir depth is 3 650 - 4180 as possible to decrease prohibitively high computational cost without unduly compromising the accuracy. In the examples presented in this

ore gas-producing basin in Mexico where workflows were implemented for automatic surveillance and optimization of gas production.� T

artificial lift method and a comparison with the top-drive PCP system are presented in this paper.

as the Muglad White Nile Blue Nile Khartoum and the Atbara basins terminate northwards at the Central African Shear Zone. The develo

facilities design and reservoir production strategies.� Gas oil ratios saturation pressures and viscosities are among the fluid parameters

thin these depressions show significant variations in age of formation complexity and size. The result of regional stratigraphy study indicat

0 API heavy oil with water cuts up to 98%. The reservoir depth is approximately 2 000 ft. Bottomhole pressure is approximately 200 psi with

roboric acid9 and mixtures of esters and fluorides to generate HF-in-situ by thermal hydrolysis.10 Reactions of some these acid systems w

elivering a crosslinker that has two (or more) organometallic complexes: one that could yield limited crosslinking at a lower temperature for

hnique to bypass skin-damage in the near-well bore region and create a high conductivity conduit for production enhancement. Fracturing w prehensive laboratory study which includes acid solubility tests X-Ray Diffraction (XRD) analysis batch reaction kinetics fines migration t e main treatment agent. Chelating agents are materials that are used to control undesirable reactions of metal ions. In oilfield applications e Fig. 2). The lithology changes from nine sands at the bottom of the well to twelve sands at the top of the productive interval. Many of these ressure of the formation. The reduction of capillary pressure to very low values allows for water block clean up even at low drawdowns. Th ta can be used to differentiate produced connate water from aquifer or injection water breakthrough.

roduction moves to more remote areas and deeper or more difficult well paths.

ls under intensive and long injection schemes are subject to create long fractures as well. Many of the late wells are planned injector wells

wed production stabilized at 914 BOPD and 1% water cut compared to a stabilized production of a vertical well at 100 BOPD and 1% water c omparison of the models’ and actual results are presented in the following sections. ymmetrical syncline with the deepest end in the north central (Figure 1) 1. The majority of the study was focused on the Riverbend field an 0.7 psi/ft. To honor the pressure gradient the models were initialized by enumeration of reservoir pressure and fluid saturation and infinites he additional perforated intervals and larger stimulation treatments result in additional value. The methodology to compare production foreca

to greatly aid in reservoir evaluations such as identification of �compartmentalization fluid spatial variations characterization of hydroca

ation and overall systemic inefficiencies.

½b. Once pressure drops below sand face pressure fluid from the formation will flow into the flowline ����������ï he hydraulic fracturing was not only to increase the productivity index of the wells but also to provide connectivity between the borehole an

enge of prospecting and exploration of that extremely geologically complicated block of resources called since then the YTZ. This referred

ble method of diagnosing the transition zone is desirable. However the formations are often of mixed and variable wettability. It has observe

gies. These technologies have reduced the finding cost through better exploration and appraisal techniques better drilling and completion p

c model. Both core and log measurements provide a tremendous amount of information to help characterize rock types and their properties

of integrating such high resolution tools in order to build a static reservoir model whose upscaling will strongly reduce its spatial resolution. A

focused-sampling cleanup introduced recently in the next-generation wireline formation testers (O’Keefe et al. 2008). DFA tools provide ½ Also the well known density-neutron separation may not always result in water free hydrocarbon production. Coupled with reservoir and fl

or the evaluation of lithology and mineralogy porosity and fluid saturations. Evaluation of these properties using a similar suite of measure

pecific shaly sand formation as using improper model that highly depends on these uncertain parameters may result in bypassing the pay z rmation as using improper model that highly depends on these uncertain parameters may result in bypassing the pay zones. uch as porosity permeability and grain density and Special Core Analysis (SCAL) data such as mercury injection capillary pressure (MICP) on. An average quantitative resistivity of invaded zone was derived by laterally averaging all 20 resitivity curves from borehole2 image log. S crystal size. Due to this geologic complexity the quantification of permeability and by extension rock typing from traditional logs and interpr ppropriate benchmark for improving estimation of net producible sand thickness in thinly bedded reservoirs. Passey et al. (Ref. 1) define pe

ion. Finally the fourth and last verification is the volume of hydrocarbon. Although crossvalidation between 3D induction and NMR interpreta

ich follow. ch fractures are artificial in origin caused by either/or the formation and the core material being disturbed or excessively stressed either dur ng the newly acquired 3D seismic well log motifs and seismic modeling of porosity attributes. Problem Definition Structural and Strati-struct

erize geologic facies object size petrophysical property continuity and reservoir connectivity (Journel and Alabert 1988 Jones and Ma 2001

lution to enhance the deeper measurements with poorer vertical resolution as shown in Suau et al. 1984 paper for the first evaluation of thi

enhance oil production. Based on the study some rules of thumb have been proposed about when it is important to consider stress reorien

xcessive mud loss internal blowout and differential sticking (van Oort et al. 2003). Drilling through such depleted sands was accomplished

mined as a key factor that defines productive potential of wells. General information The basement of the field consists mostly of Paleozoic

fines productive potential of wells.

rticularly fluid loss control additives –certain additives may cause damage by plugging pore throats in an irreversible manner.

sical analysis is affected by strong limitations in core analysis and log interpretation due to the very low porosity and naturally fractured res metimes large density-neutron separation allows us to distinguish gas from oil but in other cases lithological effects could mask it. Hydroca

ere is proper flow monitoring at the surface. This offers significant benefits in both production optimization and reservoir characterization an e top of the underlying Rumaila Formation and the other at the top of Mishrif (Fig.2). The lower part of the Mishrif consists of homogeneous

ide (CO2). The gas-oil-ratio (GOR) of the fluid is then estimated from the derived composition (Mullins et al 2005a Dong et al 2006 Fujisa phase transitions. Wireline-conveyed formation testing and sampling tools are described in detail elsewhere.6 Figure 1 is a schematic rep

dicate oil is swept by a favorable gravity-dominated displacement. As Sarah oil is a light crude of 38� API and formation water has total ch robe plugging fine laminations and depth control. Over the past 20 years in the formations we focus in this study the operational success

nduct interval pressure transient testing (IPTT).� These tests were conducted by producing through the dual packer module and monitori wellbore is influenced by mud filtrate invasion and mud cake formation. Considerable studies have been made in this area. A good summa plan involves identifying the best suited activity and then designing that activity to its optimum level. Final risk exposures for the selected a eline pressure tests for reservoir characterization faces two important limitations. On one hand the restricted thickness of the sand bodies l

of completeness a generalized stratigraphic column of Block 10 is included as Figure 2 while Figure 3 shows an arbitrarily selected cross s

aybe used to improve the performance of such wells if water is increasing the fluid column density (and therefore bottom hole flowing pressu

g picture depicting the FM framework and its different building-blocks details of the FM framework building-blocks:

flow-entities and flow-e

h the favourable mobility ratio resulted in excellent sweep efficiency. However one of the reservoirs (A6.0) was found to be almost entirely is

ovements such as $30mn per year per asset for optimization and over $90mn per year in improved Net Present Value (NPV) from planning rk-process simulation model and used it to identify and implement several cost effective production optimization opportunities of San Manu o varying interpretations.� This is especially true because no industry-wide rules have been established for the accuracy required of the s y. Typical well production rates are on the order of 10 000 to 15 000 BPFD. Field average water cut at this stage is around 84%. Present Ch

not effectively produce oil from vertical wells. The recent horizontal and multilateral wells in these shaly zones have greatly improved produc liverability. Thus we narrate a process flow that could be adopted as a guideline for field development plans requiring hydraulic stimulation ommingling etc.). Fig. 2 shows a typical well production history in this project. It becomes a real challenge to allocate production by the rese

s greater than 15ft.1 The technology uses the resistivity contrast between an adjacent bed and its orientation in 3D to calculate the distance sticated geophysical model derived from two 3D seismic surveys covering the Brenda field. Reservoir simulations indicated that the Brenda niques.�Nowadays even during the early stage of exploration and appraisal detailed reservoir models are constructed based on seismic ssure by a port; then it was connected to surface by shielded wiring which provides a continuous readout of gauge pressure once every se elds cover the highest percentage of fields and associated remaining potentials4 which makes them especially attractive. In almost any wa mpletion has been rigorously evaluated. Introduction The field study case is situated in offshore Sabah East Malaysia. After its discovery in 91 Brouwer and Jansen 2004 Sarma et al. 2005 Kraaijevanger et al. 2007). In these applications the parameters to be optimized are usu

Khalifah et al.10 Gomes and Reza11) and are generally applicable to a single well. The application of analytical solutions to full field reservo he deterministic approach the Bayesian approach associates probability distribution to the prior models and is thus considered well-suited

e gas phase the total number of variables for grid cells containing three phases is 2Nc+6 where Nc is the total number of components in t

rature4 5 6 7.� Once a problem is identified appropriate measures (such as shut-off gas/water producing intervals) can be taken to reso

id invasion into the reservoir polymer-solids deposition near the fracture face as filter cake forms clay swelling in the case of incompatible nitiated. In the field only a fraction of the injected polymer can be produced during the cleanup process typically up to 50%. Slugs of unbro efficient reservoir sweep and reduced or deferred recovery. condensate flow in vicinity of the hydraulically fractured well. Nevertheless this approach has some certain disadvantages and first of all:� ial slip. The model has been implemented in a hydraulic fracture simulator. Interfacial slip affects not only the fracture height but also the fra ¿½ In recent years numerical simulation for hydraulic fracture modeling has been introduced to the industry. Numerical simulation allows d

del he states that it is often difficult to distinguish the effects of fracture conductivity from fracture half-length. This observation leads him to bitrary fracture conductivity distribution as well as providing a more fundamental and theoretical basis for the apparent wellbore radius of ve th with orthogonal flow along the fracture. A new model is herein proposed with both the fracture geometry and flow being radial. Actually

rning methods a term that covers a large variety of methods including stacked generalization and ensemble averaging. An additional probl

ons are used instead for material balance calculations.

ry mixture causes one component to segregate to the hot plate and the other to the cold plate. Because of the density gradient caused by t

the method of constructing an M-matrix is extended so that clusters of faces are used; in our work we consider 3-dimensional grids. The pa

g stress/strain tensor fields (Bourne and Willemse 2001; Maerten et al. 2002; Bourne et al. 2001; Daly and Mueller 2004; Roxar FracPerm R

the saturation transport along streamlines. In this work we employed the implicit CFL numbers in the range of 1 to 20. The numerical meth rrent finite-difference simulators can drop significantly when detailed descriptions and complex matrix-fracture transport processes are introd

hich includes a specialised brine composition and scale precipitation model included to enable such calculations to be made whilst taking ad

r to maintain the required accuracy. Also there is no global restriction on the saturation time step since the latter may vary from one stream

lts obtained during the analysis phase as value promise for field development.

scription of method The proposed approach is analogous to the face recognition technique based on Principal Component Analysis curre have only one outlet. This restriction meant that only device models with a “gathering tree topology could be represented and loops we

VT sample in Marrat. The reservoir temperature of 275 oF is 20 oF higher than the critical temperature for this sample. Liquid saturation vs.

s ������������������������������� ���� been performed in such zones and report that if supercharging and production/depletion effects are not major complications in the gradie methods to drill successfully have been described in an earlier paper.1 In the referenced paper the basic concepts and procedures for pro ½ While mentioning a stress map we are mainly concerned about the directionality of the minimum stress across the region. l“Smart Fields Also during the past decade there has been an increasing appreciation within the industry that much of the future lies w

s shown in Figure 1. The Arctic Slope has long been considered a petroliferous province . odulus or increasing the Poisson’s ratio of the cement will decrease the stresses induced in the cement sheath and for a given situatio

ents. Aulia et al. (2001) provide a comparison of the applicability of each measurement in different environmental conditions. measurement principles were the same as for BP Harding well PN1.2 Oseberg S�r Field Description The Oseberg S�r field operated he PVT data illustrates that the oil has higher viscosities with the increasing depth hence showing the oil quality deterioration1. Figure 1 sho pe have been available for some time [2 4].� Recently an array mini-spinner has been introduced that has proven quite useful in better c

ty of tool sticking are reduced.

are largely contaminated with drilling-mud filtrate and are disposed of by pumping into the borehole in the “cleanup phase. Optical fluid in identifying wells as candidates for production enhancement 1 for determining depletion and drive mechanisms 2 and for optimizing well p by packers from previously perforated intervals (starting from the deepest depth interval). In order to decrease fluid loss the viscosity of the vantage points. The case in point is hydraulic fracture height and can it be effectively assessed using temperature logs to determine heigh

d observations of wellbore liquid unloading conditions4-11 that the criteria for the translation of entrained liquid droplets in the flow stream g g conditions4-11 that the criteria for the translation of entrained liquid droplets in the flow stream generally provides a better indication of the of permanently installed DTS systems was wireline conveyed fiber optic systems where the distributed temperature sensor can add to com

et al1 with the production increment without spare capacity some oil companies have adapted a process to monitor daily production and l

ition also affect their formation but not to a significant extent.9 Combination of fluid production including oil and water under certain circums

ing concept. Real-time data are viewable by authorized personnel anywhere around the world thus allowing virtual collaboration between fi match the well-bore temperature profile calculated from the thermal model to the early measured DTS data when reservoir layer pressures attern design and subsequent operational improvements including as optimization of steam volumes rates and cycle timing. Finally the pa mance both geographically as well as by formation. Similarly monitoring the gas-oil ratio (GOR) in the producers as well as water injection c Hence there was a crucial need for real-time sandface data a robust mechanism to deploy sensors a reliable connection technique betwe

wing needs of the Oil & Gas Company for: Controlled and secured data collection and preservation (real time remote or manual) Producti tion solution and provides recommendations for the identification of water entry in horizontal flow environments. Two Niger Delta case study

were the forerunners in this category. Thermal Decay time measurements (TDT) and Reservoir saturation estimation using Carbon-Oxygen

mum strategy for maximizing reserves in the lower two oil bearing units of reservoir thereby controlling the process at a more local level (Re and pressure and flow data. Evaluation of a number of advanced geophysical methods led to the selection of the crosswell EM method for i proximately another 2 500 CBM wells/year are estimated in Canada for the next 10 years. By comparison conventional gas production in C m varies from one coal seam to those of the other and have a significant bearing in their production characteristics even in the commingled e systems can be closed down due to mechanical hoop stress in open hole completions. Nowhere is this better exemplified than in a series 65%. In 2002 horizontal wells were experimented with in an effort to increase the wellbore's exposure to the reservoir. The results of the fir g pressures generally result from localized stress concentrations and from the consequent tortuosity associated with small apertures and c

allowed Mitchell to complete the Upper Barnett that is present in Denton and Wise Counties in addition to the Lower Barnett.� This incre various hydraulic fracturing operation schemes such as “zipper-frac and “simul-frac have been invented and tested (Waters et al. 2

ally viable production rates hydraulic fracture stimulation is a necessity. r the HCl-carbonate reactions. The acid dissociates into hydrogen and its conjugate base ions. The hydrogen ions attack the carbonate to g

ssures are required but very high flowrate are necessary for the working of the system. As such only Centrifugal Compressors suffice the pu t of coastal-deltaic sediments and crevasse splay sandstones. JS11 reservoir is represented all over the entire area by thin marine sands in

asing valves that isolate individual layers one at a time without any interventions. The TAP valves are near full bore and do not require incre

upward in the well.�� These are the criteria for moving the liquid film along the wall of the conduit upward as well as the criteria for su upward in the well.�� These are the criteria for moving the liquid film along the wall of the conduit upward as well as the criteria for su

and heterogeneity we expect a reservoir optimization scheme to prescribe qi (t) for each well i given all of the reservoir information estimat

ts the data. Finally we conclude that SA is the only viable and appropriate unbiased time-to-event methodology for evaluating ESP system

eld model (FFM) to all grid cells above and below the estimated fracture length improved the prediction compared to previous PI or skin adj

e higher oil saturations in the Middle Member and also the sometimes presence of intense natural fracturing in the adjacent brittle upper sh fracture vertical extension barriers are weak or non-existent and the underlying zone is water saturated. In addition the fibers allow for bet

imensions further complicates the analysis. nment mechanisms can now be studied with fewer approximations for hydraulic fracturing conditions. The study of the layered modulus effe ades in hydraulic fracturing applications to improve well productivity.1 The initial VES applications were with the gravel-pack completions in t d recycled waters in high rate low permeability shale reservoirs (Arthur et al. 2009). Water volumes for a typical slickwater hydraulic fractu million psi. echnique has become the preferred option to stimulate unconsolidated sandstones with low reservoir pressures. Currently 40% of stimulati djusted frac fluid systems and pump schedules. These purposely -created barriers are placed prior to the main fracturing treatment by pump ailable in the market today. An innovative technique used for stimulating these horizontal wells was introduced. It combines mechanical and ow GOR hence there is no gas injection for pressure maintenance however the produced gas in used for lifting the oil through gas lift system

of a single productive layer and isolating it from previously opened intervals requires a significant number of downhole operations. These o der of magnitude less than the in-situ value. This fact can be explained by the effect of microcracking and inelasticity near the fracture tip.1 owing into the core was measured as a function of time and the total fluid loss coefficient vs. permeabilities was plotted in Figure 3.�Also

their origin to either hearsay or experience and that were generally followed by the operators were (a) to fracture-stimulate the wells only w

voir into the fracture as opposed to considering only flow along the fracture length. e rock types found in the Cotton Valley sand interval.� Calcite cementation quartz overgrowth and overburden pressure have greatly redu

from sonic logs and/or vertical seismic profiling (VSP) data4. Commonly the velocity model is then adjusted to locate perforation shots to t

y is 13-16%. The average oil saturation is 50-60% with reservoir pressure at 248 bars. The AC-12 formation situated below the AC-11 is ch well. A particularly popular use of radioactive tracers is for the determination of propped fracture height. Fracture height measurement throu

present a case study by use of microseismic imaging to determine the geometry of a hydraulic fracture. A two-stage fracture treatment was

miscible fluids. The presence of a small parameter incorporating surface tension for immiscible fluids allows to determine theoretically the ch conductivity as a function of reservoir parameters and fracture treatment in the context of Siberian oilfields.

The cores are cut to shape and potted along the edges with a rubber sealant using a mold.�They are saturated under vacuum with 2%

e nineties. After 2000 the increase in water injection rate has restored the reservoir pressure and become one of the main factors to restart nt as a result of sliding on the natural fracture after the hydraulic fracture crossed it. Some fracture design models include a calculation for t ng conventional gas lift. The reasons for using these variable valves are usually their higher pressure ratings their ability to deliver a wider r n guns and a packer. The guns were run with weighted spacers and swivels to orient the guns to perforate on the high and low sides of the any benefit compared to vertical wells. Post production analysis on the deliverability of horizontal wells in reservoirs such as matrix heterog ny benefit compared to vertical wells. Post production analysis on the deliverability of horizontal wells in reservoirs such as matrix heterog of optimized filtercake this will prevent the reservoir damage due to mud invasion Easy removal of the filtercake by applying a minimum d

azon River drainage system and covers an area of approximately 80 000 km2 which is very prolific on production of oil and gas. It is geologi

s (ICVs) installed in intelligent wells. The settings of these valves can be varied to optimize the inflow profile along the well in response to m �� Fracture #1 extending through a flawless section of the block (tip mechanisms); and ������� ii.����ï

e of reservoir? Answers of these questions allow us to evaluate reservoir recoverable reserves. Traditionally a full scale well test and an in

le completion perforations provide the communication between the wellbore and the reservoir. They are the conduits for treatment fluid inje er. Well-0 was perforated in static underbalanced conditions and tested at 334 standard cubic meters per day (Sm3/d). In May 2003 the op L/MMSCF. This phenomenon was also supported by adjacent well performance which was shut in due to high water production. Nitrogen lif static underbalance which is now a well recognized technique for perforation cleanup. The appropriate level of static underbalance has be zone in the formation around the perforating tunnel to impair the well’s productivity or injectivity. Perforating damage (skin effect) can be e from approximately 8 000 ft to 10 000 ft in depth. Porosity ranges from 6% to 15% and permeability from 0.01 md to 7.0+ md. Water satu ill be at balance conditions so any subsequent perforating runs will be made at balance and not benefit from an underbalance surge for cle mber test (Alexander 1977) surge test (Simmons 1990) and perforation inflow test (Hawkes and Hategan 2004) have a similar or the sam

nent with little time for engineers to run another round of full qualification tests the engineers or project managers can decide whether the g

analysis added one producer and one injector into a new portion of the reservoir.

ol means5. ate the reactivity of the shales. The initial Open Hole Gravel Pack (OHGP) wells in an offset Angola deepwater block were drilled with oil ba

enhole gravel packing experience in the industry has been in water based drilling fluid environments new challenges emerged for gravel p

en Hole Gravel Pack (OHGP) completions the length of the planned wells (up to 2500 m) would incur both technical and logistical/cost chall rmed the direct communication between several producers and injectors. Water injection post wormhole-like failure is very inefficient as the steps: Optimum perforation phasing and size Near-wellbore consolidation Tip screen out fracturing using proppant flowback control such

to address the issue and optimize production in that part of the field. A Phase II of the study discussed here was initiated by Schlumberger Introduction The giant Messla field is located in the southeast portion of Sirte Basin in Libya approximately 500 km southeast from Bengha he contingency plan to properly address the problem and maximize economic production. The study started with data acquisition. Various w

uid-shale interactions were derived based on a database estabilished for a number of drilling fluids and shales encountered in the basin in ed in the mid 70’s as was cited by Metcalf et al. (2000). These acids have much higher viscosity than regular acids or acids containing u ich is very difficult to predict because it inherently depends on a stochastic process and is affected by a wide range of parameters. Most pre have endured just such an evolutionary process. Production from the Strawn Formation in Terrell County increased significantly in the 1990

ded to apply this system in Tengiz field and analyze the results of the stimulation treatments to evaluate their effectiveness. Whenever pos at low- and high-injection rates respectively.[3-8] Besides not creating deeply penetrating wormholes both extreme cases can cause a fa

sized. Recent marked effort in this regard included an analytical modeling of the tubing pickling process and its verification using field acidizi

They normally do not react to their full acid capacity because of the release of CO2 from carbonate dissolution (3) the degree of hydrogen

d treatment is the correct downhole placement of the acid for optimum zonal coverage.2� Though over the years there have been many sing hydrochloric and mud acid systems and water based hydraulic propped fracturing treatments using polymers to viscosify�the frac flu of propagation.� By increasing the flow rate from a low to a high value the dissolution pattern changes from a face dissolution to a worm own successful restimulation candidates in the industry. An attempt will be made to highlight the attributes mentioned in this paper through s ™s Ratio and “in-situ stress. An additional benefit from such log is the stress profile which is one of the most important parameters to e

% and permeability equals 15–60 mD. The oil-saturated thickness totals 7–11 m and the gas saturated thickness amounts to 19 m. Th

water breakthough intervals with the current completion in place is highly required." y of cement squeeze decisions are based on the results of physical communication tests the value of continuing to run cement bond logs w extract transmissibility to water from late-time data captured from slug tests by using a straight-line technique. Much later Cooper et al.2 an day initial build-up to get a first estimate of the reservoir pressure and key parameters Modified isochronal test: Three 8-hour flowing and sh oduction performance of the well in combination with direct physical measurements of layered reservoir flow rates and wellbore flowing pre

rvoirs have been a topic of continuous research due to the fact that many producing fields of the world are found in such type of formations. vestigation; i.e. how much reservoir volume if investigated for a given duration of a transient test? For exploration wells the reservoir volum stment.� For operations engineers operating artificially lifted systems the main concern is to make sure that equipment is running efficien ve been built around the idea of applying a special time transformation [e.g. the logarithmic multirate superposition time (Agarwal 1980)] to

ates and Iran. Currently on Total ABK field well testing of around 65 oil producers is performed on two test separators. Total ABK wishes to ned in the testing systems Permanent monitoring requirements More of these requirements for wet gas well testing have already been pre

Multiphase-flowmeter interpretation emphasizes the liquid rate measurement and the application of multiphase flowmeters has been predo

measurement [Ref 2]. This leads to a compact and efficient solution. tested areas in the reservoir.

orating knowledge of both reservoir and gauge physics. It is efficient and straightforward to implement and may be used on either real-time o the surface acquisition unit so that there was no requirement for downhole electronics. There were 7 electrodes in each zone at a spacing

d system performance that cannot be engineered away and that may happen even when job is perfectly executed. Mitigation measures mus

reservoir or geological formation with reservoir characteristics (porosity and permeability) with pores filled with brine. The term ‘salineâ€

s fuel burning and industrial processes (Figure 1). The foremost contributor to increased atmospheric CO2 is fossil fuel combustion for po ey undergo stress changes and deformation[iii]. The mechanical response of the sealing components to the loads induced by well drilling a

of all service companies involved in detail planning and risk identification workshops are a critical factors for success. In the operational ph

of natural CO2 deposits and preliminary assessment of commercial CO2 fields in the USA. This paper discusses the results of the first stud ne solution that has been used primarily in water-based systems has been laminated sand analysis. This type of analysis has been applied

al porosity types that are fractured/micro-fractured and cavernous/micro-cavernous pores can always be observed in the altered granitoid ro manent abandonment of zones in addition to temporary wellbore areas isolation for tubing integrity tests and general pressure testing (Wellh ment and confirming where the TOC would be after the intervention. This by implication makes it difficult to determine if a good cement job h

n and the modeling results are presented in this paper. 7). Therefore the characteristics of gas/liquid flow cannot be applied directly to oil/water flow in most cases. Generally knowledge of the di d using the Brinkman model (1952). The model predictions of the flow pattern transition water holdup and pressure gradient are compared of the well.�Intelligent completions also can guarantee regulatory requirements to back-allocate production from the wellhead measurem timization opportunities of San Manuel Production System. Project Scope In August 2006 Schlumberger-Mexico was contracted to develop ases and the asphaltenes aggregate. As the field matures oil cross-flow from the higher oil pressure zone into the lower gas pressure reserv and operation of the subsea system will be discussed. Flow Assurance Properties of Waxy Crude Oils The experimental data generated in and must first hydrate to carbonic acid (H2CO3) before becoming acidic and corrosive. The corrosion produces iron carbonate (siderite) sc

ent data. Abdel Fattah et al.6 showed that both Whitson and Torp and Coats procedures provide excellent match with compositional simulat

complexities above often zones with unwanted fluids are perforated. Selectively testing each producing layer to identify fluids using conve asily have very similar in-situ densities but very different compositions consequently very different pressure-volumetemperature behaviors.

luid properties reliable enough for economic screening. Therefore it is imperative that representative high-quality WFT samples are collecte

ectives were achieved. various other mitigating or accentuating factors. Detect the onset and evolution of reservoir souring upon the implementation of water injec

e reservoir fluid is near its critical point. In heavier oils compositional grading can be due to a number of causes or a combination thereof. T

ed (VIS/NIR) absorption spectroscopy is widely used to assist wireline fluid sampling today. Identification of gas oil and water is now well e

n and volumetric behavior is complex. When a critical transition exists in the reservoir the fluid column then changes from a bubble point flu rger fractions of formation fluid replace the OBM filtrate. An accurate value of the GOR is important for many applications including crude-

wavelength. At any time instant the measured OD is a weighted linear combination of the spectra of the undesired OBM filtrate and the des nt wavelengths and a simplified hydrocarbon composition can be quantitatively determined from the NIR spectrum. With the latest DFA tool

sity of the oil. Viscosity of water-in-oil emulsions increases as the water cut increases before the so-called emulsion inversion point beyond

facilities (Raghuraman et al. 2007). It also establishes the salinity for petrophysical evaluation and fingerprints the aquifer for studies on ba

for conversion this is unavoidable and has been similarly required to obtain flow rates at standard conditions with a separator or any other production could be maintained. At these production conditions significant variations of fluids properties can be observed on surface both

oper design is to avoid an aggressive fluid which even though it imparts high rock dissolution (Table 2) may cause severe nearwellbore dec

characteristics of the inhibitors. To address these problems and limitations of the current available chemistries associated with salt remova

is much less than undamaged rock. The perforation tunnel creates a flow path between the reservoir (at pressure pr) and the wellbore (a ion is further confirmed by thousands of samples retrieved from electrical submersible and rod pumps production tubing and downhole sca r production. This paper presents the applications of a phosphino-polyacrylate scale inhibitor (PPASI) in the stimulation of multi zone gas w

oblems. This would tend to indicate that UZ field would not have significant production declines due to scale. .�Reservoir depth is 3 650 - 4180 m (11 975 – 13 665 ft) subsea initial temperature was 160 �C at 4 155 m (320 �F at 13 362 ft) y. In the examples presented in this paper the pilot points are distributed uniformly through out the reservoir. The sensitivity analysis is done

optimization of gas production.� The implementation at AIB was divided into three successive phases.� The first phase includes an ass

ntral African Shear Zone. The development of the rift basins of southern Sudan is related to the processes that operated not only within cen

ies are among the fluid parameters that determine the economic viability of a field development. Downhole fluid analysis (DFA) is a powerfu

of regional stratigraphy study indicates a major East Africa rift basin appeared and developed in the Late Jurassic to early Cretaceous. Early

ssure is approximately 200 psi with bottomhole temperature of 120F. The heavy oil viscosity is more than 5 000 cp at standard conditions (F

tions of some these acid systems with various clays were discussed by Al-Dhahlan et al.11 In general during sandstone acidizing treatmen

sslinking at a lower temperature for initial proppant transport and the second complex for higher temperatures experienced in the fracture.ï

oduction enhancement. Fracturing was started in the Bach-Ho field as early as 19941. Target zone for fracturing has mostly been the Oligoc ch reaction kinetics fines migration tests core flow tests was conducted on field cores to evaluate and compare the performance of the ne of metal ions. In oilfield applications chelating agents (Frenier et al. 2000) are frequently added to acidic stimulation fluids to prevent precip he productive interval. Many of these sand beds contain hydrocarbons but produce oil water or gas depending on the fluid saturations rela lean up even at low drawdowns. The capillary pressure can be decreased by altering the wettability decreasing the interfacial tension or b

ate wells are planned injector wells or converted fractured producer wells that are accordingly fracture stimulated therefore avoiding signifi

al well at 100 BOPD and 1% water cut. A follow-up horizontal sidetrack was completed in 2005 with similar results. These two wells currentl

s focused on the Riverbend field and some analysis has also been done in the Natural Buttes field.� This paper focuses on three major f ure and fluid saturation and infinitesimal vertical permeabilities were entered into the models to prevent gravity equilibrium. Wells are stimu dology to compare production forecasts using a laminated sand analysis and stimulation designs is a useful tool for exploiting bypassed tigh

riations characterization of hydrocarbon-water transition zones injection fluid monitoring and so on. On the other hand the complexity of

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½c. Once the pretest piston stops expanding the flowline the pressure will build-up onnectivity between the borehole and all pay intervals in each of the commingled-lenticular reservoirs. The installation of electronic gauges

d since then the YTZ. This referred both to the capabilities of seismics which could not differentiate some fine features of the geological cro

nd variable wettability. It has observed that the saturation exponent of the famous resistivity-based Archie equation depends on the initial ï¿

ques better drilling and completion practices and have also helped in accelerating the production from mature fields.

erize rock types and their properties. Lately NMR has been proven to provide two fundamental parameters – relaxation time and amplitud

rongly reduce its spatial resolution. Also the pricing of such high resolution tools limited their use to specific tasks (horizontal wells cored ve

Keefe et al. 2008). DFA tools provide results in real time and at reservoir conditions. Current DFA techniques use absorption spectroscopy o uction. Coupled with reservoir and fluid complexities above often zones with unwanted fluids are perforated. Selectively testing each produ

ties using a similar suite of measurements acquired while using wireline-logging tools has been presented previously (Herron et al. 2002). H

rs may result in bypassing the pay zones. In the present paper an approach is proposed to estimate the uncertainty in the calculated wate assing the pay zones. y injection capillary pressure (MICP) and relative permeability curves can be utilized during the workflow. Even though such core data may b curves from borehole2 image log. Separation borehole image resistivity curve from the Induction curves caused by invasion of the formatio ping from traditional logs and interpretation methods does not yield satisfactory results (Fig. 2).� One of the primary objectives in this cas oirs. Passey et al. (Ref. 1) define petrophysical thin beds as contiguous units of rocks with thicknesses between 1 in. (2.5 cm) and 2ft (61 cm

een 3D induction and NMR interpretation techniques does not guarantee an accurate evaluation of reserves it does indicate that the results

ed or excessively stressed either during and/or after the coring has taken place. Whilst drilling induced fractures seen by image logs provide Definition Structural and Strati-structural trapping mechanisms play critical roles for hydrocarbon entrapment within Upper Cretaceous reser

nd Alabert 1988 Jones and Ma 2001 Deutsch 2002).

4 paper for the first evaluation of thin gas-bearing sands using well logs2 and Galford et al 1986 paper on tool response enhancement aka

important to consider stress reorientation in a reservoir development plan. Stress reorientation around horizontal wells is an often mention

depleted sands was accomplished in the Ursa field in the GOM using water-based mud with monomer and resin materials that exhibit large

e field consists mostly of Paleozoic carbonates that also include some layers of siliciclastic and volcanic rocks. The overall structure of the f

an irreversible manner.

porosity and naturally fractured reservoir environment. Despite of this the measurement of a reliable porosity with the NMR technique in th gical effects could mask it. Hydrocarbon type can also be interpreted from pressure gradient plots. However a reliable pressure gradient ne

on and reservoir characterization and can also be used to justify UBD. The objective of this paper is to demonstrate the use of a reservoir-s e Mishrif consists of homogeneous mud dominated lithologies which is deposited in a slightly rimmed ramp environment. The upper part sh

t al 2005a Dong et al 2006 Fujisawa et al 2006). Additionally the differences in absorption spectra between reservoir fluid and oil-base m where.6 Figure 1 is a schematic representation of one possible configuration of WFT tool with two DFA modules a pumpout model sample

API and formation water has total chlorides in the region of 148 000 mg/l. SCAL has been performed on a number of occasions throughou n this study the operational success ratio of downhole formation pressure testing (valid test vs. total tests) has remained at an average of 3

he dual packer module and monitoring the pressure at the dual packer as well at the vertically displaced observation probe.� The acquire n made in this area. A good summary of the literature on the dynamics of invasion and mud cake formation is presented by Hammond1. In nal risk exposures for the selected activity are estimated and reported whereby potentially high risk aspects are known to the implementatio icted thickness of the sand bodies limits the number of data points and hence the reliability of pressure gradients for fluid identification. The

shows an arbitrarily selected cross section of Block 10 included here to illustrate the severe degree of faulting which is a problem particular

herefore bottom hole flowing pressure); however for mature field artificial lift optimization is challenging without a major workover to lower th

ing-blocks:

flow-entities and flow-entity lists expressions actions instructions balancing strategies procedures fluid system

FM adap

.0) was found to be almost entirely isolated from its aquifer resulting in no discernible pressure support. It was estimated that the volume of

t Present Value (NPV) from planning solutions can be routinely exploited within the average asset. What is needed is a road map for the a mization opportunities of San Manuel Production System. Project Scope In August 2006 Schlumberger-Mexico was contracted to develop ed for the accuracy required of the static and dynamic model before the dynamic model can be used for forecasting. is stage is around 84%. Present Challenges The XJG reservoirs are being developed using two fixed platforms. At this time no additional s

zones have greatly improved production performance and field recovery. The petrophysics and depositional environment of the reservoirs a plans requiring hydraulic stimulation. It is important to first describe the state of understanding of the Saih Rawl field prior to the ongoing d ge to allocate production by the reservoirs.

ation in 3D to calculate the distance to this bed together with its azimuthal orientation with respect to the borehole. In practice inversions a mulations indicated that the Brenda pool could be efficiently depleted with four horizontal production wells three in the east accumulation a ls are constructed based on seismic information tied to well information such as logs cores pretests and longer term tests.�With the co out of gauge pressure once every second. At the surface these data are temporarily stored on a computer the Acquisition Surface Unit (A specially attractive. In almost any water flood water passes by the oil on a macroscopic scale due to the heterogeneity of the reservoir.� East Malaysia. After its discovery in 1971 development began in 1981 with installation of an integrated drilling and production platform. 14 parameters to be optimized are usually well-flow rates bottomhole pressures (BHPs) or choke-valve settings. Because these are not mixed

nalytical solutions to full field reservoir problems where multiple well interference effects and reservoir boundaries are fully accounted for h and is thus considered well-suited for post-data inference and uncertainty assessment by defining a posterior distribution of models and sa

the total number of components in the fluid models excluding water component using natural variable formulation.

ucing intervals) can be taken to resolve the problem and optimize well performance.8 9. Simulation of horizontal wells is very challenging du

swelling in the case of incompatible fluids broken-polymer/fines migration into the reservoir matrix and chemical interactions between the f typically up to 50%. Slugs of unbroken residuals were reported during the post-fracture production and indicate the existence of gel resid

ain disadvantages and first of all:� large amount of the grid cells and excessive requirements to the computational resources as sequenc ly the fracture height but also the fracture width and fracturing pressure. The effects and the implications on fracturing treatments are demo dustry. Numerical simulation allows detailed reservoir properties layering pressure-volume-temperature (PVT) and field and well geometr

ength. This observation leads him to construct his flow simulator based on two major tenets: first that the fracture is of infinite conductivity; r the apparent wellbore radius of very low conductivity fractured wells than had existed previously. �� At this point the general concep metry and flow being radial. Actually not so new since Sneddon and Elliot had started to derive it as early as 1946.1 At this time however no

mble averaging. An additional problem is introduced when the data sets are small. This is a common situation in petroleum-engineering and

e of the density gradient caused by temperature and concentration gradients convection flow occurs and creates a concentration difference

onsider 3-dimensional grids. The paper is organized as follows: Section 2 describes our transmissibility upscaling method (TU-method) wit

nd Mueller 2004; Roxar FracPerm Reference Manual 2005). The boundary conditions consist of (1) location/geometry of fault surface (2) s

ange of 1 to 20. The numerical method described so far can be used for an arbitrary discretization of a streamline. We can further accelerat acture transport processes are introduced. Traditional reservoir-modeling workflows have been deterministic with a single best effort" desc

ulations to be made whilst taking advantage of the reduction in numerical dispersion that may be obtained by performing streamline simula

the latter may vary from one streamline to another. For some complex processes much of the computational effort during streamline simu

Principal Component Analysis currently used in computer vision applications . In a face we have pixel illumination as function of space whi could be represented and loops were not permitted. This paper describes how the formulation has been extended effectively to allow any

or this sample. Liquid saturation vs. pressure resulting from a CVD experiment of this PVT sample is shown in Figure 2-b. The sharp increa

����� ������������������������������� ot major complications in the gradient interpretations then there are two generic pressure gradients which can be observed in transition zo sic concepts and procedures for proper design of an underbalanced coiled-tubing drilling procedure for a multilateral well are reviewed and ss across the region. ndustry that much of the future lies with the effective management of existing production and the continued development of mature fields.ï¿

ment sheath and for a given situation will decrease the risk of failure. In the modeling papers discussed above there has been little discus

onmental conditions. The Oseberg S�r field operated by Norsk Hydro is situated 130 km west of the Norwegian coast. The main oil-producing reservoir is th il quality deterioration1. Figure 1 shows typical well logs in Mauddud Formation in Sabriyah Field. The seawater injection water flood progra at has proven quite useful in better characterizing stratified flow in high-angle wells [5]. General Well Description The main oil productive re

he “cleanup phase. Optical fluid analyzers or resistivity sensors are typically used to monitor filtrate contamination in real time and samp chanisms 2 and for optimizing well placement.3 Although the monitoring and surveillance of the pressure data allows engineers to see the t crease fluid loss the viscosity of the injected brine was increased by adding low concentration of polymer and CO2. In the beginning of eac temperature logs to determine height containment in a tectonically stressed environment. This paper will illustrate several case studies whe

ed liquid droplets in the flow stream generally provides a better indication of the ability of a well to continuously transport wellbore liquids to t lly provides a better indication of the ability of a well to continuously transport wellbore liquids to the surface. emperature sensor can add to complement or perform measurements not possible with standard production logs including monitoring gas

ess to monitor daily production and lost production. However in some other cases the lack of a Loss Management System and limited Proc

g oil and water under certain circumstances can also form tight and viscous emulsions and thus pose hindrance to well productivity. The em

wing virtual collaboration between field staff and off-site service- and operating-company experts throughout the operation. This paper inclu data when reservoir layer pressures and other parameters are known (i.e. from logs). As the flow profile changes with time the model can th ates and cycle timing. Finally the passive seismic and surface deformation monitoring can also be used to track unwanted steam breakouts roducers as well as water injection conformance is critical for a robust reservoir management strategy. The high-deviation producing wells w reliable connection technique between upper and lower completions and a multidiscipline interpretation strategy to maximize the value of t

al time remote or manual) Production surveillance capitalizing on real-time data acquisition system investment Production allocation proc nments. Two Niger Delta case study wells validate the precision of the measurements against the results of the APLT multi-probe multi-spi

on estimation using Carbon-Oxygen ration have been used regularly since its inception. More recently the resistivity measurement through

he process at a more local level (Ref. 1). The benefits of this process are more efficient and faster recovery. The potential drawbacks are gr ion of the crosswell EM method for interwell saturation monitoring (Bhatti et al. 2007). This paper shows the results of the first time lapse in on conventional gas production in Canada is 5 Tcf/year declining by 2.5% per year. Estimates of world coalbed methane reserves range fr racteristics even in the commingled production scenario. s better exemplified than in a series of papers by Jeffery & Connell 2 3. In this piece of work small horizontal wellbores were drilled in coal s o the reservoir. The results of the first horizontal wells compared to vertical wells were three times the estimated ultimate recovery at twice t sociated with small apertures and changing fracture orientations in the vicinity of the wellbore.� Furthermore because of the large inhere

n to the Lower Barnett.� This increased EURs by roughly 20% to 25%. Also in the late 1990s Mitchell began to experiment with restimula invented and tested (Waters et al. 2009).

rogen ions attack the carbonate to generate Ca2+ CO2 and H2O. Equation 1 shows acid dissolution of limestone."

ntrifugal Compressors suffice the purpose. Surface Venturi As shown in fig 2 it is a metallic structure of the geometry as shown. It has a co entire area by thin marine sands intercalated with shoreface top carbonate streaks. Most part of the field reserves (over 60%) is associated

ear full bore and do not require incremental reductions of ID and thus allow normal cementing operations. The TAP valves also have unique

upward as well as the criteria for suspending and transporting entrained liquid droplets in the flow stream upward.� It has been observed upward as well as the criteria for suspending and transporting entrained liquid droplets in the flow stream upward.� It has been observed

of the reservoir information estimated until that point. The smart completion may then be programmed to follow this qi (t) as closely as poss

hodology for evaluating ESP system performance. The analytical process we propose represents the given data parsimoniously and provid

compared to previous PI or skin adjustment techniques. Using this methodology the number of potential fracture stimulation candidates ha

uring in the adjacent brittle upper shale. d. In addition the fibers allow for better proppant distribution throughout the hydraulic fracture. The better final proppant distribution is a resu

he study of the layered modulus effect has been investigated using a finite element method that can rigorously account for different moduli i with the gravel-pack completions in the mid 1980s in the Gulf of Mexico.2 Surfactant-gelled fluid was used to replace the polymer-based flui r a typical slickwater hydraulic fracture treatment can average 715 m3 (6 000 bbl) per stage with 6 to 10 stages per horizontal well. Large tre

essures. Currently 40% of stimulations performed in unconsolidated sandstones for Petroleos de Venezuela S.A. (PDVSA) in West Venezu e main fracturing treatment by pumping a mixture of specialty particles. The method is not unique to Western Siberian conditions and may duced. It combines mechanical and chemical diversion using selective openhole completion along with the VES diverting acid technology. or lifting the oil through gas lift systems. The application of Electrical Submersible Pumps for artificial lift is growing in these fields as the te

er of downhole operations. These operations are typically conducted by multiple interventions using slickline wireline or coiled tubing. Som nd inelasticity near the fracture tip.1 2 Some attempts have been made to develop the model of hydraulic fracture propagation in elastoplas ties was plotted in Figure 3.�Also shown in Figure 3 is the typical trend for total fluid loss coefficient of crosslinked polymer fluids.�Th

o fracture-stimulate the wells only when they fall below economic limit and (b) when fracturing avoid usage of water-based fluids since Mor

erburden pressure have greatly reduced the permeability and porosity of the sand layers.� Sand porosities range from 2% to 12% with pe

usted to locate perforation shots to their assumedly correct positions4. The velocity model adjustment can be done in a number of ways but

ation situated below the AC-11 is characterized by complex and aerial heterogeneous structure of several sandstone bodies which complic Fracture height measurement through the use of radioactive tracers and subsequent logging runs allow engineers to assess�: Post sti

A two-stage fracture treatment was monitored where a sandstone formation had been stacked vertically by a regional tectonic thrust fault. T

ows to determine theoretically the characteristic shape and width of viscous fingers[7 8] while in miscible fluids theoretical analysis allows t

e saturated under vacuum with 2% KCl prior to use.�The cell construction begins with placement of the lower core which includes a ga

me one of the main factors to restart the hydraulic fracturing operations. gn models include a calculation for the additional pressure needed to open and force fluid through a fracture branch that is not aligned perp tings their ability to deliver a wider range of gas lift rates as well conditions change the elimination of stability concerns resulting from overs ate on the high and low sides of the casing. The upper completion string consisted of a production seal assembly (stung inside the packer) n reservoirs such as matrix heterogeneous and non-conventional formations showed a direct correlation to the completion and stimulation n reservoirs such as matrix heterogeneous and non-conventional formations showed a direct correlation to the completion and stimulation m e filtercake by applying a minimum drawdown to the formation. This will enable maximum productivity from the reservoir without any potentia

oduction of oil and gas. It is geologically continuous with the Putumayo basin in Colombia and the Maranon basin in Peru separated only b

ofile along the well in response to monitoring data obtained from downhole sensors and to the predictions of reservoir and well models. Acti ½ï¿½ï¿½ï¿½ï¿½ ii.����������� Fracture #2 (normal to fracture #1) intercepting angled filled artificial joints p

nally a full scale well test and an interference test are conducted to determine well productivity and well-to-well connectivity respectively.

e the conduits for treatment fluid injection and reservoir fluid production.� For natural completions the perforating job is designed with the er day (Sm3/d). In May 2003 the operator started the drilling phase of Well-1 located 800 m west from Well-0. The original objective of We to high water production. Nitrogen lift operation was performed on adjacent wells but failed to sustain the production. Despite the decline tre level of static underbalance has been extensively researched1 2 3; however more recent investigations4 5 have presented relevant eviden orating damage (skin effect) can be minimized by producing perforating tunnels free of crushed sand particles and other perforating debris. om 0.01 md to 7.0+ md. Water saturation can vary from 20% to 50%. Hydrocarbons are gas-condensate in depletion with partial water supp from an underbalance surge for clean-up. The well log data was evaluated to determine optimal perforating intervals and the applicability o gan 2004) have a similar or the same pressure transient as that of the UBP we discuss in this paper. All these tests essentially share a com

managers can decide whether the gun will survive (be retrievable) by using the modeling tool instead of merely relying on their experiences

pwater block were drilled with oil based mud and the hole was displaced to brine prior to running screens1. Significant problems were initia

ew challenges emerged for gravel packing wells drilled with oil-based fluids.[2] A significant level of progress has been made in recent year

oth technical and logistical/cost challenges in addition to the risks associated with running screens. e-like failure is very inefficient as the water passes through to producer via the wormhole channel and doesn’t sweep any oil. Remedial sing proppant flowback control such as resin-coated proppants and fibers. Fines stabilization

here was initiated by Schlumberger in October 2005 to address a further 25 wells located in three areas (GC1 GC2 and GC3) that were de ately 500 km southeast from Benghazi (see Figure 1). The field operated by AGOCO has been producing for over 30 years and since the rted with data acquisition. Various wireline logs such as microresistivity image log and dipole sonic log were acquired from some of the key

shales encountered in the basin in previous studies. The likelihood of wellbore instability and sand production were assessed using in-hous n regular acids or acids containing uncrosslinked polymers. Two types of crosslinked acids are available. The first type consists of a polyme wide range of parameters. Most predictions of conductivity are made with the empirical correlation developed by Nierode and Kruk.1 This c y increased significantly in the 1990’s with the discovery of the Abilene Christian University (ACU) Strawn and Deer Canyon Strawn fiel

their effectiveness. Whenever possible pre- and post-job production logs and pressure transient tests were performed to better evaluate both extreme cases can cause a failure of the matrix integrity in the near-wellbore region. For a given acid system the optimum injection r

and its verification using field acidizing job data6 7. The studies showed that the process again involved the three basic mechanisms namel

olution (3) the degree of hydrogen ion generation decreases with increasing temperature 6 7 and (4) the cost of organic acid is significantly

er the years there have been many products and techniques developed in the industry for acid diversion the preferred ones generally have g polymers to viscosify�the frac fluid have demonstrated a very low success rate. Proppant fracturing treatments �though recognized es from a face dissolution to a wormhole and then to a uniform dissolution pattern.� In the wormholing regime a maximum permeability i es mentioned in this paper through some well-known case histories. Based on the existing knowledge base on the restimulation identificatio the most important parameters to estimate fracture height growth. Additionally since the four Frontiers members were clearly identified a

ated thickness amounts to 19 m. The oil saturation factor totals 0.51–0.67 while the gas saturation amounts to 0.44–0.64. The initial fo

ontinuing to run cement bond logs was questioned. Conversely applying the policy of communication tests was costly and time consuming hnique. Much later Cooper et al.2 and Ramey et al.3 developed complete type-curve analysis techniques for estimating reservoir paramete nal test: Three 8-hour flowing and shut-in periods followed by a 6-day extended flow period and a 14-day build-up Pressure Traverse To c r flow rates and wellbore flowing pressures. Methodology The completion and production optimization methodology reported here relies o

are found in such type of formations. These reservoirs differ in geological and petrophysical properties from homogeneous reservoirs. Addit xploration wells the reservoir volume investigated is one of the main objectives of running DST or production tests. Therefore how far pres ure that equipment is running efficiently and to avoid catastrophic failures. uperposition time (Agarwal 1980)] to the test pressure data so that the pressure behavior observed during individual flow periods would be s

est separators. Total ABK wishes to improve the accuracy of testing its production wells by using a multi-phase flowmeter which will allow to as well testing have already been presented in Theuveny et al [1]. The basics of the gas well testing with dual energy gamma – venturi mu

tiphase flowmeters has been predominantly for liquid-rich flow stream allocation and well testing."

nd may be used on either real-time or recorded data. No modifications to gauges or surface hardware are necessary. Furthermore error bo lectrodes in each zone at a spacing of 20 ft. A schematic drawing of the electrode array mounted on the outside of insulated joint sections o

executed. Mitigation measures must be adopted in this case to ensure a robust design. This is especially true for wells entering CO2 storag

ed with brine. The term ‘saline’ expresses that CO2 storage is planned in reservoirs not intended to be used as fresh water resource

CO2 is fossil fuel combustion for power generation transport industry and domestic use. Energy from fossil fuels has provided a high sta o the loads induced by well drilling and completion CO2 injection and the corresponding effects on the risk of leakage must therefore be as

rs for success. In the operational phase the work in the subsurface team was optimised through using 3D visualisation tools. These 3D too

discusses the results of the first study oriented to evaluate the CO2 proven reserves of Quebrache field and its potential application as EOR s type of analysis has been applied since the early 1990s primarily in turbidite plays[4] and not verified with production. The analysis used

observed in the altered granitoid rocks (figure 1)." and general pressure testing (Wellhead production tubing…etc) as well as selective acid stimulation and water/ gas control treatments. T to determine if a good cement job has been performed.

ses. Generally knowledge of the distinctive features of oil-water systems together with those of gas/liquid systems can be used in the futu and pressure gradient are compared with the present experimental results. The model performance under different flow conditions is analyz duction from the wellhead measurement to the individual reservoirs for reserves booking. An operator would not accept a predetermined s er-Mexico was contracted to develop an integrated study of San Manuel’s production facility (PEMEX’s Muspac Asset). The project ne into the lower gas pressure reservoir might also lead to precipitation and plugging of the gas sand. The consequences of asphaltene prec The experimental data generated in flow assurance studies are generally used to evaluate potential for solids deposition. This information produces iron carbonate (siderite) scale which can function as a protective layer under elevated temperatures increased pH and low turbu

nt match with compositional simulation results when PVT experimental data are matched with an EOS model and then used to output the M

g layer to identify fluids using conventional surface test equipment is a viable approach but can be costly. In this paper direct pressure and ure-volumetemperature behaviors. Conventionally delineation of reservoir fluids variations in a column required sampling with lab analysis

gh-quality WFT samples are collected early in any exploration or appraisal campaign.

on the implementation of water injection or other enhanced recovery techniques. Determine the price of a unit hydrocarbon produced and i

f causes or a combination thereof. These include water washing evaporative fractionation incompetent sealing shales dynamic charge of

n of gas oil and water is now well established (Smits et al. 1995). Problematic OBM contamination is quantified during sampling jobs using

hen changes from a bubble point fluid to a dew point fluid without encountering a fluid meniscus or contact. Further anomalies may arise als many applications including crude-oil typing and production facilities design. Conventionally GOR is measured in a PVT laboratory by flas

undesired OBM filtrate and the desired formation fluid. Initially the measured spectra are dominated by the OBM filtrate. With increased pu R spectrum. With the latest DFA tool 13 the hydrocarbon composition comprises five groups: methane (C1) ethane (C2) propane to pentan

d emulsion inversion point beyond which the continuous phase changes to water (i.e. water-in-oil emulsion switches to oil-in-water emulsio

erprints the aquifer for studies on basin hydrology. Water composition is important for production strategies involving inhibitor injection wells

ditions with a separator or any other devices. Figure 2 illustrates a generic flow path from line to standard conditions for any MFM and any fl s can be observed on surface both in terms of composition and Condensate/Gas Ratio (CGR).

may cause severe nearwellbore deconsolidation which is increased by the relatively high temperature. Based on previous experience it w

mistries associated with salt removal inhibition and to improve the lifetime of a squeeze treatment a R&D project was initiated to develop n

at pressure pr) and the wellbore (at pressure pw).�The pressure difference pr-pw�can drive a surge flow either from the wellbore in production tubing and downhole scale sample from surface piping samples and also dozens of production fluid samples from many fields n the stimulation of multi zone gas wells. Specifically described is the monitoring of scale inhibitor return and the design optimization. Geolo

C at 4 155 m (320 �F at 13 362 ft) and initial pressure was 604.5 bar at 4 155 m (8 768 psia at 13 362 ft).�Some areas of the reservo rvoir. The sensitivity analysis is done with respect to permeabilities since it is essentially the correlation structure of permeability which quan

.� The first phase includes an assessment of the existing data workflow for operation and surveillance process and a standardization eff

es that operated not only within central Africa but also along the western and eastern continental margins. The Sudanese interior basins ar

hole fluid analysis (DFA) is a powerful technique to help identify compositional grading and frequently missed compartmentalization of the de

e Jurassic to early Cretaceous. Early rift sediments interbedded with coarse rift clastics derived from surrounding uplifted basement source

an 5 000 cp at standard conditions (Figure 4) and the reservoir rock is oil wet with high H2S content (up to 9 mole %). The Nukhul formation

during sandstone acidizing treatments the following main precipitation reactions occur that can lead to formation damage.12 13

ratures experienced in the fracture.� This approach would manage friction pressures.� However the gel would still suffer irreversible d

acturing has mostly been the Oligocene as it has reasonable recoverable reserves does not have water zones nearby like the Miocene and compare the performance of the new sandstone acidizing system with current systems being used in the above oil field. c stimulation fluids to prevent precipitation of solids as the acid spends on the formation. The use of chelating agents is one proposed appro pending on the fluid saturations relative permeabilities rock and fluid characteristics. Presently fluid prediction success rate varies between ecreasing the interfacial tension or by increasing the permeability (or pore radius) of the formation. Penny et al.[5] used a non-water wettin

stimulated therefore avoiding significant water bypass or overshooting of the water front between layers within the formation. The uneven in

ilar results. These two wells currently produce 1300 BOPD and less than 1% water cut. As a result additional development will be impleme

This paper focuses on three major formations (Figure 2): Wasatch (Porosity (favg )= 11% Water Saturation (Sw )= 55% Avg Net = 90 ft) M gravity equilibrium. Wells are stimulated with multiple limited-entry hydraulic fracturing to attain economical gas-production rates. Operator eful tool for exploiting bypassed tight gas. Geographical and Geological Background The geographical setting for this case study is LaSall

On the other hand the complexity of the WFT operation has dramatically risen and continues to rise due to the increase in the types of WFT

he flowline the pressure will build-up to sandface pressure ����4. Multiple pretests may be performed on the same set and when The installation of electronic gauges below the ESPs together with daily monitoring has enabled the operator to evaluate hydraulic fracture

me fine features of the geological cross-section under several trappean and saliferous caps in high-velocity cross-section and to the boreho

ie equation depends on the initial �oil saturation and varies across the capillary transition zone for mixed-wet and oil-wet reservoirs. Furth

mature fields.

ers – relaxation time and amplitude – that are required for linking pore properties to fluid distribution combined with rock typing.

cific tasks (horizontal wells cored vertical wells for calibration purpose for instance) while today high oil prices should make their use at ent

ques use absorption spectroscopy of reservoir fluids in the visible-to-near-infrared (NIR) range. The formation-fluid spectra are obtained in r ated. Selectively testing each producing layer to identify fluids using conventional surface test equipment is a viable approach but can be co

ed previously (Herron et al. 2002). However the suite of measurements available with this new tool and the fact that many of the measure

e uncertainty in the calculated water saturation from the different shaly sand models due to the uncertainty in the input petrophysical and el

w. Even though such core data may be available only on a few key wells in a given field the fine tuning of parameters based on the detailed caused by invasion of the formations with the oil base mud. Generally the zones with larger invasion have higher mobility and those with m of the primary objectives in this case study was to identify logging technologies and interpretation methods that would improve the predictio between 1 in. (2.5 cm) and 2ft (61 cm) that exhibit a narrow distribution of petrophysical properties but are bounded above and below by ot

rves it does indicate that the results are plausible. What we seek first is to be able to say yes hydrocarbon is indicated by both tools or no

ractures seen by image logs provide important geomechanics data (i.e. pertaining to stress directions stress magnitudes and rock failure) ment within Upper Cretaceous reservoirs in the Al-Khafji area. The newly acquired 3D seismic data were aimed at delineating the stratigraph

on tool response enhancement aka alpha processing4. The third is the sandcount approach from a high-resolution dipmeter – later subs

horizontal wells is an often mentioned but rarely quantified aspect of production planning and reservoir development. Stress reorientation a

and resin materials that exhibit larger fracture propagation pressure than do those of oil-based mud (however the fracture opening pressur

c rocks. The overall structure of the field represents a elongated anticline of an irregular shape that is located northwest of Mezhov arch. Inte

orosity with the NMR technique in these naturally fractured clastics reservoirs has demonstrated to be a viable and reliable alternative this ever a reliable pressure gradient needs sufficient and well-spaced points that might be difficult in thinly laminated beds or where there is a

demonstrate the use of a reservoir-simulation tool coupled with a method for parameter identification through automated reservoir characte amp environment. The upper part shows the occurrence of fine to very fine grained peloidal packstones to grainstones facies deposited in th

etween reservoir fluid and oil-base mud (OBM) or water-base mud (WBM) are used to estimate fluid sample contamination with the drilling modules a pumpout model sample modules containing the sampling bottles and two single-probe modules. On the right side of this figure

n a number of occasions throughout As Sarah field’s life and these tests have confirmed the reservoir to be more oil than water wet. Th s) has remained at an average of 30% despite technological innovations in both wireline and drilling. In Table 1 we summarize the main re

observation probe.� The acquired pressure and rate data were analyzed as a vertical interference test revealing permeability and perm tion is presented by Hammond1. In the early nineties Goode and Thambynayagam2 developed a model that exploits the pressure transient ects are known to the implementation team and accounted for in economic evaluations. Generating options and screening them to achieve gradients for fluid identification. The error band of formation testers (given by depth accuracy and gauge resolution) becomes of relative im

ulting which is a problem particularly important when investigating the feasibility of re-development opportunities such as waterflooding or m

without a major workover to lower the depth of injection point or changing out to a pump system. When gas oil ratio increases well product

procedures fluid system

FM adaptors to reservoir simulators and surface-network simulators enabling the abstraction of the implementati

It was estimated that the volume of the aquifer was approximately one hundredth of the aquifer in the adjacent reservoirs with about 0.25 b

at is needed is a road map for the adoption and development of these IAMs along with a statement and agreement of the principles that g er-Mexico was contracted to develop an integrated study of San Manuel’s production facility (PEMEX’s Muspac Asset). The project r forecasting. latforms. At this time no additional slots are available for new well locations on either platform. This situation limits infill drilling to accelerate

onal environment of the reservoirs are briefly described as follows. aih Rawl field prior to the ongoing development program in 2004.

Reservoir Characterization. The average characteristics of the Barik a

e borehole. In practice inversions are performed in real time while drilling using both directional EM curves and other LWD resistivity curves lls three in the east accumulation and a fourth in the west accumulation. Reservoir simulations also indicated that the initial production rate nd longer term tests.�With the commencement of production these models are altered and conditioned to honor observed production dat uter the Acquisition Surface Unit (ASU) (which connects the input data streams from all the various surface and downhole sources) and a e heterogeneity of the reservoir.� This might lead to reasonable spots of bypassed reserves which are not accessible through any existin d drilling and production platform. 14 wells were drilled targeting production from reservoir sand at 8000 ft tvdss. An additional drilling platfor ettings. Because these are not mixed-integer problems gradient-based methods are used commonly to solve them and the adjoint method

boundaries are fully accounted for have been presented for porous media with homogeneous and anisotropic permeability by Busswell et. a osterior distribution of models and sampling multiple realizations from this distribution.

ormulation.

orizontal wells is very challenging due to the fact that they often produce from a large interval with substantial heterogeneity in rock properti

chemical interactions between the fracturing fluid and the matrix such as pH alteration or polymer adsorption (Holditch 1979). In addition h d indicate the existence of gel residues inside the fracture after the cleanup process. The incomplete degradation of the polymers in the fra

computational resources as sequence difficulties with grid generation around fracture (especially for complex shape fracture) problems with s on fracturing treatments are demonstrated through a numerical example and a field case study. e (PVT) and field and well geometry to be incorporated into the model. It is therefore possible to model the fluid flow from matrix to fractur

e fracture is of infinite conductivity; and second that the fracture conductivity and the fracture half-length can be merged into a single term ¿½ At this point the general concept of fracture stimulation design using the dimensionless productivity index as a basis has been reasona y as 1946.1 At this time however nobody could imagine that the era of horizontal drilling would eventually come so their difficult mathematic

tuation in petroleum-engineering and geosciences applications in which the cost of data or collection logistics may limit the number of meas

d creates a concentration difference between the top and bottom of the column. Analytical and numerical models have been presented to a

y upscaling method (TU-method) without imposing monotonicity constraints on the solution matrix. Section 3 presents a brief discussion on

ation/geometry of fault surface (2) stress conditions or displacement conditions on the fault surfaces and (3) the remote loads applied to th

treamline. We can further accelerate the method by using the adaptive mesh refinement as described in our previous work [2]. In this work nistic with a single best effort" description of the reservoir and little or no quantitative evaluation of uncertainty in the data and its impact on

ned by performing streamline simulations as opposed to finite difference calculations.

ational effort during streamline simulation is spent on the solution of the 1D transport equations [12]. Therefore a fast numerical method for

llumination as function of space while in a continuous pressure data we have pressure as a function of time. Therefore a shift has been m n extended effectively to allow any number of outlets from a segment thus enabling loops to be incorporated in the ICD model. We apply t

own in Figure 2-b. The sharp increase of liquid-dropout volume immediately below saturation pressure shown in Figure 2-b illustrates a typi

½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ï¿½ (3) ������ after rewriting the Forchheimer equation. Base hich can be observed in transition zones of homogeneous limestones.�The profile of figure 1 is the most general and it is on this we focu a multilateral well are reviewed and those design concepts were used to formulate the strategies for the project discussed in this paper. Ni

nued development of mature fields.�What may not be so clear is how to apply smart technologies to mature fields with a legacy infrastru

d above there has been little discussion of how to determine the appropriate parameters that describe the cement mechanical behavior. Th

he main oil-producing reservoir is the Tarbert formation within the Brent group which is of variable reservoir quality with permeabilities rang seawater injection water flood program was designed to reduce the pressure depletion and increase the sweep efficiency. After successful w escription The main oil productive reservoirs in Chayvo lie 8-9 km offshore from the drilling rig location at depths of 2400-2900 m TVDSS (s

ontamination in real time and sample collection into sample chambers begins once specific criteria to ensure representative water-sample e data allows engineers to see the trends such as reduction in kh or increase in skin with time geomechanical analysis must also be perfor er and CO2. In the beginning of each stage the injection rate was increased stepwise up to 45 bbl/min to result in a final wellhead pressure ll illustrate several case studies where solely temperature logs have been used in a tectonically stressed environment to determine fracture

uously transport wellbore liquids to the surface.

uction logs including monitoring gas lift valves6 leak detection7 and detecting flow behind casing/tubing.

anagement System and limited Process Automation does not allow the Prodcution Engineer to take advantage of the information available f

hindrance to well productivity. The emulsification process can be aggravated by the presence of asphaltenes and waxy materials.10

hout the operation. This paper includes several examples of WFT surveys that were monitored and supervised in real time. The cases pres changes with time the model can then be used to predict the reservoir pressures from the change in temperatures. Of course this could b d to track unwanted steam breakouts. Thus combined monitoring of passive seismic and surface deformations offers critical information for The high-deviation producing wells will be mostly completed with sand screens and are capable of up to 50 000�BOPD flow rates. The m n strategy to maximize the value of those sensors.

estment Production allocation process standardization Production allocation traceability and audit trail Automated consolidation and acc ts of the APLT multi-probe multi-spinner production logging tool. The Challenge Skepticism towards attempting to acquire Production Logg

he resistivity measurement through casing opened new vistas in estimating saturations under suitable conditions efficiently and accurately (

ery. The potential drawbacks are greater costs and higher local pressures which could induce uneven flows. s the results of the first time lapse in the WI pilot where decrease in resistivity due to 4 months of water injection in the lowermost units of th coalbed methane reserves range from 4 416 to 8 556 Tcf with 749 Tcf located within the US. Production of coalbed methane has steadily in

ontal wellbores were drilled in coal seams to degas prior to mining. The wells did not produce adequately from the horizontal open hole wel stimated ultimate recovery at twice the well cost. Horizontal wells offered an economic solution to areas outside the core and reduced the n hermore because of the large inherent anisotropy in tight gas shales near wellbore stress concentrations are considerably more variable th

began to experiment with restimulation treatments.� In many cases well performance matched or exceeded the original initial production

limestone."

f the geometry as shown. It has a converging section throat and a diverging section. The metal thickness should be adequate enough to be ld reserves (over 60%) is associated with oil-water zones. Productive reservoirs show mostly good lateral continuity and are underlain by va

s. The TAP valves also have unique helical ports that align to any preferential fracture plane regardless of the orientation of the valve in the

m upward.� It has been observed by Turner et al1 and Oudeman9 that the flow stream velocity required to continuously move the liquid f m upward.� It has been observed by Turner et al1 and Oudeman9 that the flow stream velocity required to continuously move the liquid f

to follow this qi (t) as closely as possible. In contrast to poor sweep problems among vertical wells to improve contact one may think of ha

given data parsimoniously and provides performance indicators (with confidence bounds) in response to specific questions. At the risk of pre

al fracture stimulation candidates has increased by 200%.

r final proppant distribution is a result of the proppant suspension properties of the fibers that physically prevent the proppant gravitational s

orously account for different moduli in a hydraulic fracture simulator (Smith et al. 2001). Two effects of high-modulus layers on fracture heigh ed to replace the polymer-based fluids in sand-control applications to improve retained pack-permeability and to aid inducing concentration stages per horizontal well. Large treatment volumes for these applications offer a unique opportunity for cost savings if flowback water can

zuela S.A. (PDVSA) in West Venezuela are frac-and-packs. The importance of the frac-and-pack technique relies on the fact that less rig t estern Siberian conditions and may be applied to any formation where height growth is suspected to occur at the expense of fracture extens he VES diverting acid technology. is growing in these fields as the technology that allows these pumps to handle sand production has evolved in the recent years. In the e

ckline wireline or coiled tubing. Some of the new methods are placing more downhole hardware in the ground to reduce interventions. Ot c fracture propagation in elastoplastic media. In particular the analysis of the easier case of impermeable elastoplastic rock is presented in of crosslinked polymer fluids.�The results indicate that the fluid loss coefficient for the VES system is comparable to that achieved with

age of water-based fluids since Morrow formation is water-sensitive.� When opting for option (a) though potential loss of production was

osities range from 2% to 12% with permeabilites