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Home My WebLink AboutAIO 022 B ,---- ~ AREA INJECTION ORDER FILE COVER PAGE XHVZE This page identifies oversize material and digital information available for this individual Order file and weather or not it is available in the LaserFiche file. Please insure that it remains as the first page in this file. Af 0 ÔJ.1-. jj Area Injection Order File Scan Date. 7jJ #mit.~ Color Materials # / ---L-. Scanned infB/Wl Color Circl~ o Added (date) Init.~ Ini 1. Greyscale #í OCompleted (date) Ini 1. Digital Data Added to LaserFiche File o o o CD's - DVD's - Diskettes - # # # o YesO No o YesO No o YesO No Init. Ini 1. Ini1. Oversized Material Added to LaserFiche File Maps Mud Logs Other # # # DYes 0 No DYes 0 No DYes 0 No Init. Ini1. Init. General Notes or Comments about this file. If any of the information listed above is not available in the LaserFiche file, or if you have any questions or information requests regarding this file, you may contact the Alaska Oil & Gas Conservation Commission to request copies at 279-1433, or email usat:AOGCC_Librarian@admin.state.ak.us SCANNED JUL 1 5 2004 ) " / 1. April 28, 2003 2. April 26, 2004 3. December 6, 2004 ) ,/' AIO ORDER NO. 22B AURORA OIL POOL Application for Rehearing (confidential exhibits in Confidential room) Request for a Proposed Aurora EOR Pilot BPXA request to extend pilot miscible injection (AlO 22B.002) Corrected Administrative issued 1/10/05 AREA INJECTION ORDER 22B ,,-.., ,,- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska Prudhoe Bay Field Aurora Oil Pool Area Injection Order No. 22B Erratum Notice May 9, 2003 The Commission has found the following error in Area Injection Order No. 22B, issued May 6,2003, which is hereby corrected as follows: The first numbered paragraph on page 6 following "NOW, THEREFORE, IT IS ORDERED THAT:" reads "AIO 22A is withdrawn." This paragraph should read instead "This order supersedes AIO 22A." ~-~_' _ "'''<,' :~':'c:'~.;-;:::~::....-:-:.:.~~~ DONE at Anchorage, Alaska and dated May 12,2003. Daniel T. Seamount, Jr.; Commissioner Alaska Oil and Gas Conservation Commission ra-J¡ L~ Randy Ruedrich, Commissioner Alaska Oil and Gas Conservation Commission SCANNED JUL 1 5 2004 - .~ ,~ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska Prudhoe Bay Field Aurora Oil Pool Area Injection Order No. 22B May 6, 2003 IT APPEARING THAT: 1. By letter and application dated December 9, 2002, BP Exploration (Alaska) Inc. ("BPXA") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") modifying Area Injection Order No. 22 ("AIO 22") authorizing underground injection of miscible injectant ("MI") for enhanced oil recovery in the Aurora Oil Pool ("AOP"), Prudhoe Bay Field, on the North Slope of Alaska. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on January 28, 2003. 3. The Commission did not receive any protests or comments concerning this application. 4. A hearing concerning BPXA's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 333 W. 7th Avenue, Suite 100, Anchorage, Alaska 99501 on March 4,2003. 5. BPXA provided additional information on February 28, 2003 and on March 7,2003. 6. On April 3, 2003 the Commission issued Area Injection Order No. 22A ("AIO 22A") denying BPXA's application to inject enriched gas in the AOP. 7. On April 28, 2003 BPXA applied for rehearing of AIO 22A and supplied additional information in support of their application. SCANNED JUL 1 5 2004 .""-', ,-- Area Injection Order 22 h. May 6, 2003 .fage 2 of8 FINDINGS: 1. Operators/Surface Owners (20 AAC 25.402(c){2) and 20 AAC 25.403(c){3)) BP Exploration (Alaska) Inc., ExxonMobil Alaska Production Inc., ConocoPhillips Alaska, Inc., Chevron U.S.A. Production, and Forest Oil Corporation are working interest owners. The State of Alaska is the landowner. 2. Proiect Area Requested for Enhanced Recovery The AOP is defmed as an accumulation of oil that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26- 12-12 well. The geology of the AOP is described in Conservation Order 457 ("CO 457") and AIO 22. 3. Description of Operation (20 AAC 25.402(c){4)) The AOP is developed from the Prudhoe Bay S-Pad. Tract operations within the pool began in November 2000. The Commission approved water injection with the issuance of AIO 22 on September 7,2001. The proposed project involves the cyclical injection of water alternating with enriched hydrocarbon gas into the oil column of the Kuparuk River Formation of the AOP. The injectant will be comprised of hydrocarbon gas, enriched with intermediate hydrocarbons, principally ethane and propane, which is designed to be miscible with the reservoir oil. The proposed source of this enriched gas is from pools within the Prudhoe Bay Unit and processed within the Prudhoe Bay Central Gas Facility. Requested timing for injection of enriched gas into the AOP is second quarter of 2003. Miscible gas injection is planned within the blocks having established water injection, North of Crest and West Blocks. Expansion to the remaining blocks is dependent upon performance of primary production and waterflood operations. Additional recovery as a result of miscible gas injection is projected at 3-5% of the original oil in place. 4. Well Logs (20 AAC 25.402(c)(7)) Well logs for the proposed injection wells are on file with the Commission. 5. Mechanical Integritv (20 AAC 25.402(c){8)) All newly drilled and converted injection wells have been completed in accordance with 20 AAC 25.412, thus satisfying mechanical integrity requirements. The casing programs for S-lOli, S-104i, S-107i, S-110i, S- 112i, and S-114Ai were permitted and completed in accordance with 20 AAC 25.030. Injection well tubularshave premium threads to prevent tubing leaks and maintain integrity during injection of enriched gas. SCANNED JUL 1 5 200~ ..--, ,~ Area Injection Order 22 b May 6, 2003 .t>age 3 of8 Cement bond logs (ultra sonic imaging tool) run in Wells S-104i and S- 112i indicate good cement bond across and above the Kuparuk River Formation. The Commission has approved water-flow logs completed in Wells S-I01i, S-107i and S-114Ai to confirm injection containment into the target zone. BPXA has applied for conversion of S-110 from production to injection status. Evidence of sufficient cement integrity is required prior to approval. 6. Iniection Fluid and Rates (20 AAC 25.402(c)(9)) a. Produced Water: The Aurora waterflood project uses produced water from GC-2. The composition of GC-2 produced water and compatibility issues were addressed in the original AIO 22 application. Maximum water injection capacity at AOP is estimated at 40,000 BPD. b. Miscible Hvdrocarbon Gas: The proposed project requests approval for injection of enriched hydrocarbon gas from the Prudhoe Bay Central Gas Facility. No compatibility issues are anticipated in the formation or confming zones. Planned maximum enriched gas injection at AOP is estimated at 20 million SCF per day. c. Source Water: Source water from the Prince Creek Formation may be used to supplement water injection if compatibility between Prince Creek Formation water and AOP formation fluids can be demonstrated. d. Lean Gas: Approval was requested to inject lean produced gas for reservoir pressure maintenance. Compatibility with the formation is not an issue as the gas is of similar composition to AOP produced gas. e. Other Fluids: Other fluids proposed for injection from time to time include: 1. Non-hazardous water collected from PBU reserve pits, well house cellars and standing ponds, and 2. Tracer fluids to monitor reservoir performance. 7. Iniection Pressures (20 AAC 25.402(c)(10)) Enriched gas and water injection operations at the AOP are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Maximum proposed surface injection pressure is 2800 psi for water and 3800 psi for gas. ~ SCANNED JUL 1 5 2004 ,..., ,~. Area Injection Order 22 b May 6, 2003 l)age 4 of 8 8. Fracture Information (20 AAC 25.402(c)(11}) With a maximum surface water injection pressure of 2800 psi, the injection gradient will be 0.85 psijft, assuming no friction losses, which will not propagate fractures through the cònfining layers. The overlying Kalubik and HRZ shales, which have a combined thickness of approximately 110 feet, have a fracture gradient 0.8 to 0.9 psi/ft. The underlying Miluveach/Kingak shale sequence has a fracture gradient of approximately 0.85 psi/ft. 9. Water Analysis (20 AAC 25.402(c)(12)) The compositions of injection water and AOP connate water were provided in Exhibit IV-4 of the original AIO application. Water analysis from the nearby Milne Point Prince Creek Formation was provided in the April 28, 2003 application for rehearing. 10. Aquifer Exemption (20 AAC 25.402(c)(13)) On July 11, 1986, the Commission approved Aquifer Exemption Order 1 ("AEO 1") for Class II injection activities within the Western Operating Area of the Prudhoe Bay Unit. The AOP is entirely within the area covered by AEO-l. 11. Hydrocarbon Recovery and Reservoir Impact (20 AAC 25.402(c)(14)) The Commission denied BPXA's original application because insufficient technical information was supplied to support that the injectant would remain miscible throughout the planned flood area. BPXA fully addressed the concerns within the April 28, 2003 application for re-hearing. Reservoir Depletion Plan and Field Development: Due to high structural complexity, phased development of the AOP was pursued. Reservoir surveillance from a period of primary production helped define reservoir compartments and appropriate placement of water injectors. Miscible gas injection will begin in the West and North of Crest Blocks where water injection has been established. Water injection in the South East of Crest Block is planned with conversion to injection of S-110 and S-1l2. Production within the Crest Block began in mid March 2003 with startup of wells S-1l5 and S-1l7. An injector will be considered for the Crest Block dependent upon primary production results. A local water injection booster pump is being evaluated to increase water injection support within the AOP. Reservoir Pressure and Minimum Miscibility ("MMP"): Slim tube experiments with Prudhoe Bay enriched gas injectant and Aurora oil yielded a MMP of 2700 psi. BPXA provided an update of the well shut-in pressure measurements and evaluated the information for validity-;-- All shut-in reservoir pressure measurements were above 2700 psi. Reservoir simulation indicates the average field pressure is above 3100 psi, with SCANNED JUL 1 52004 r---, ~ Area Injection Order 22 h May 6, 2003 Page 5 of8 about 90% of the field above the MMP. Areas below the MMP are limited to local producing well areas. Effect of Delaved Depletion: Reservoir mechanistic studies performed by BPXA show insignificant reserve loss from delayed waterflood if the average reservoir pressure is maintained above 2400 psi. MI injection was simulated for two separate average reservoir pressure cases. The runs at 3400 psi and 2700 psi show comparable incremental recoveries. Reservoir Voidage: Water injection has recently increased and is equal to or slightly exceeds reservoir withdrawal in both the North of Crest and West Blocks. GORIs within the waterflood area have continued to decline, suggesting good waterflood support. Injection line repair has resulted in increased water injection rates and associated increased wellhead injection pressures. Planned water injector and MI conversions and the potential water injection booster pump will provide further voidage replacement. Reservoir Surveillance: BPXA supplied a plan to acquire reservoir pressure measurements in 2003. The number of reservoir pressures planned exceeds that required by C0457, and adequately addresses the issues raised by the Commission within AIO 22B. Lean Gas Iniection: Approval of lean gas injection is premature at this time. Insufficient information was provided regarding impact upon ultimate recovery. Administrative approval allowing lean gas injection may be sought at a later date when plans and recovery benefits are better defined. 12. Mechanical Condition of Adiacent Wells (20 AAC 25.402(c)(15}) Mechanical integrity has been established for the wells within ~ mile radius of proposed injectors. Mechanical integrity is based upon calculated cement tops being at an adequate height above the injection zone to prevent fluid that is injected into the AOP from flowing into other zones or to the surface. CONCLUSIONS: 1. The application requirements of 20 AAC 25.402 have been met. 2. There are no freshwater strata in the AOP area. 3. The proposed water and miscible gas injection operations will be conducted in permeable strata and will involve injection above the parting pressure of the Kuparuk Formation in the AOP. 4. Injection pressures up to 2800 psi for water and 3800 psi for gas will not propagate fractures through the confining interval. Inj~çted fluids-will- be ," confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. SCANNED JUL 1 52004 .--.. ,~, Area Injection Order 22 h May 6, 2003 fage 60f8 5. Enriched gas injection from the Prudhoe Bay Unit will preserve reservoir energy and enhance ultimate recovery within the North of Crest and West Blocks. Expansion will be dependent upon the production performance under primary recovery and waterflood and the success of the miscible injection within the North of Crest and West Blocks. 6. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 7. Fluids approved for injection must be compatible with the AOP Formation. 8. Depletion plan update and approval are needed prior to beginning injection of immiscible hydrocarbon gas. 9. The current average reservoir pressure is above the minimum miscibility pressure of 2700 psi. Though some producers are below this pressure, the enriched gas will remain miscible within the flood front provided the average reservoir pressure remains above this pressure. 10. BPXA's depletion strategy and development plan for the coming year will provide improved reservoir understanding and are designed to result in greater ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: 1. AIO 22A is withdrawn. 2. This order supersedes AIO 22 issued September 7, 2001 (as corrected September 17, 2002). 3. Rules 2,3, and 8 of AIO 22 are revised and Rule 9 of AIO 22 is added. 4. Underground injection of fluids pursuant to the projects described in BPXA's application for AIO 22, application of December 9, 2002 for MI injection, and rehearing request of April 28, 2003 is permitted in the following area, subject to the conditions, limitations, and requirements established in the rules set out below and statewide requirements under 20 AAC 25 (to the extent not superseded by these rules, Conservation Order 457, or subsequent amendments). Umiat Meridian Township Range Sections Tl1N R12E N YJ Sec. 3 T12N R12E S YJ Sec 17; SE % Sec 18; E YJ Sec 19; All Sec 20; All Sec 21;W Ij2NW Ij4,S YJ Sec 22; SW % Sec 23; SW % Sec 25; All Sec 26; All Sec 27; All Sec 28; N Y2, Se % Sec 29; E YJ Sec 32; All Sec 33; All Sec 34; All Sec 35; N YJ, SW Y. S 36 . .--~ ,.- 4 ec - .... ............,.,.........'-- .....:....~..,.....- ... SCANNED ,/111 Î 5 ?nn4 ,~ ~ Area Injection Order 22 b May 6, 2003 rage 70f8 Rule 1 Authorized Infection Strata for Enhanced Recovery 'Source AIO 22) Injection is permitted into the accumulation of hydrocarbons that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well. Rule 2 Infection Pressures 'Amended this Order AIO 22B) The injection operations shall not allow fractures to propagate into the confining intervals. Surface wellhead injection pressures shall be limited to 2800 psi for water and 3800 psi for gas. Rule 3 Fluid Infection WeDs 'Amended this Order AIO 22B) The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. The application to drill or convert a well for injection must be accompanied by sufficient information to verify the mechanical condition of wells within one- quarter mile radius. The information must include cementing records, cement quality log or formation integrity test records. Rule 4 Monitorin2 the Tubin2-Casin2 Annulus Pressure Variations 'Source AIO 22) The tubing-casing annulus pressure and injection rate of each irtjection well must be checked at least weekly to confirm continued mechanical integrity. Rule 5 Demonstration of Tubin2-Casin2 Annulus Mechanical Inte2ritv 'Source AIO 22) A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection, following well workovers affecting mechanical integrity, and at least once every four years thereafter. Rule 6 Notification oflmpro~er Class II Infection 'Source AIO 22) The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 7 Other conditions 'Source AIO 22) a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. ..-'t"'-- .,. .... ........-' .-.... : ,. SCANNED JUL 1 5 2004 ~, ,-, Area Injection Order 22 b May 6, 2003 ;age 8 of8 Rule 8 Administrative Action 'Amended this Order AIO 22B) Unless notice and public hearing is otherwise required, the Commission may administratively waive the requirements of any rule herein or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Rule 9 Authorized Fluids for Enhanced Recovery 'New rule this Order AIO 22B) The fluids authorized for injection and conditions of the authorization are as follows: a. produced water from the AOP or Prudhoe Bay Unit processing facilities; b. source water from the Prince Creek formation provided that the water is shown to be compatible with the AOP formation and administrative approval to inject is obtained from the Commission; c. enriched hydrocarbon gas processed within the Prudhoe Bay Unit processing facilities, with the following conditions: 1. reservoir pressure must be maintained to ensure miscibility of the injectant, and 2. expansion of injection outside of the North of Crest and West Blocks must be administratively approved prior to long-term injection; d. immiscible hydrocarbon gas from the AOP or Prudhoe Bay Unit processing facilities provided that Commission approval of the associated depletion strategy and surveillance plans is obtained prior to start of injection; e. tracer survey fluid to monitor reservoir performance; and f. non-hazardous filtered water collected from AOP well house cellars and well pads. DONE at Anchorage, Alaska and dated May 6,2003. (f Alask Oil and Ga onservation Commission 0~ Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission L~c~~ Alaska Oil and Gas Conservation Commission .. ...... ... SCANNED J U L 1 5 2004 ~. ~ n~!'ì ! í ! ¡ , , J I 'U \...J 11 ! . i ¡ L~ Cëù "\.'\, ® FRANK H. MURKOWSKI, GOVERNOR AI/ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO 457A.003 and 22B.OOl Mr. Gil Beuhler GPB Waterflood Resource Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Beuhler, By letter dated April 26, 2004, BP Exploration (Alaska), Inc. ("BPXA") requested authorization to conduct a pilot miscible injection (MI) project in Aurora Oil Pool ("AOP") Wells S-1l2, S-110 and S-1l6. The Commission approved AOP miscible gas injection for enhanced recovery purposes by Conservation Order 457 A (CO 457 A), dated May 15, 2003 and Area Injection Order (AIO 22B) dated May 6, 2003. Rule 7 of CO 457 A and Rule 9 of AIO 22B require that approval be obtained prior to expansion outside of the North of Crest and West Blocks of the AOP. Wells proposed for the pilot are outside of this approved area. Injection is planned to start mid-May in Well S-112 and S-llO, within the South East of Crest Block, and in mid-September in Well S-116i, within the Crest Block of the AOP. Pilot miscible injection for 4-6 weeks is proposed to verify long-term feasibility of MI injection, and to stimulate the formation, improving water injection rates for these wells. The reservoir pressure in the injectors appears to be above the minimum miscibility pressure ("MMP") of 2700 psi, although the same producers have reservoir pressures lower than the MMP. Pilot operations for short-term injection may provide valuable information for later long term expansion of the area under MI flood, potentially enhancing recovery. SCANNED JUL 1 5 2004 ~ ,~ ADMINISTRATIVE APPROVAL NO 457A.00I and 22B.00I May 11,2004 Page 2 of2 The Commission approves BPXA's request to inject miscible gas into AOP Wells S-112, S-IIO and S-116 subject to the conditions, limitations, and requirements set out below and statewide requirements under 20 AAC 25 (to the extent not otherwise superseded by AIO 22B and Conservation Order 457A). · Separate sundry approval for conversion to MI injection service must be obtained. · Miscible gas injection is limited to no more than 3 months duration in each well. · Review of the information obtained during the test period must be presented to the Commission before April 1, 2005. This approval expires on December 31, 2004. chor e, Alaska and dated May 11 ~2004. ../ (ì)~ i~/ Daniel T. Seamount, Jr. Commissioner ~. _.- ....- -,~- SCANNED JUL 1 5 2004 Orders and Administrative Approvals /" ~ '1=:;:;:::::'::":::::::::::::':'::'::::':::"::::::':"":;:;::::'::'::::·..·T:::::·::··::::::::::::::·"··:·::::·:·:::::·::···:::.::::::::::::..:';',::::::::::.::,..:":::.:::"::::,::,:::::::::::::::::::::':;:;',,,::.:;::::::.::::c::::::::.:,:.:::...:.::::::::::::::::::::::i.·· DIO 23.001.doci Content-Type: appl1catlOnlmsword i ! j SCANNED JUL 1 5 2004 10f2 6/16/20048:08 AM Orders and Administrative Approvals r'- ~ l~ontent-EnCoding: base64m. .mmmil =..... ----- r-- r--- .. ....... ';1 ! ! Content-Type: application/msword' AI03.3.doc I ¡¡ . !mmmm' I~~~~~~~~~~~~~~~:?~~~?~m ............. m ..... .... .. .; i j....... Content-Type: application/msword Content-Encoding: base64 Content-Type: application/msword Content-Encoding: base64 I~~~~~:..... .........1. Conten.t·-Ty..pe:....a.ppl.icat.l.on/.m sw..or.d...!......[ D I 025( Corrected).doc! : Content-Encoding: base64 . . ...................................... ...."~.~....... -.... SCANNED JUL 1 5 2004 20f2 6/16/20048:08 AM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wadman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ,r--... ~~ Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 North Slope Borough PO Box 69 Barrow, AK 99723 . ---., ~" David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 SCANNED JUL 1 5 2004 /YJJl/j¿~ /(/ {Þ/Jr/ßtf ~1f ) 1f (ID~ ~~ ru~1 ~ / AI{A~HA. OIL AND GAS / CONSERVATION COlWlISSION ¡ ) FRANK H. MURKOWSK/, GOVERNOR 333 W. ]TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Corrected ADMINISTRATIVE APPROVAL NUMBERS C0457A.OO4 and AI022B.OO2 Mr. Gil Beuhler G PB Waterflood Resource Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Beuhler: By letter dated December 6, 2004, BP Exploration (Alaska), Inc. ("BPXA") requested authorization to extend current pilot miscible injection (MI) operations in Aurora Oil Pool ("AOP") Wells S-112, S-110 and S-116 ("Pilot Operations"). The Commission on May 11 gave approval for Pilot Operations through December 31, 2004. Due to operational delays and low injection rates, only S-110 has been on miscible gas injection, and only 1/3 of the total miscible injectant volume planned for the Pilot Operations has been injected. You have stated. that, with favorable conclusive results from the Pilot Operations, you will apply for a larger scale project. The Commission finds that the requested change will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. The Commission approves continuation of MI injection through September 30, 2005 into AOP Wells S-112, S-110 and S-116, subject to the conditions, limitations, and requirements set out in AIO 22B and CO 457 A and statewide regulations under 20 AAC 25 (to the extent not otherwise superseded by AIO 22B and Conservation Order 457 A). It is a condition of this approval that BPXA provide written documentation to the Commission of the results of the Pilot Operations no later than October 31, 2005. .-"'=--~,.. ~¡-w '" mD at orage, Alaska and dated JanU~10' 00 . I ~~~.~...\,.-~.\\~.:~..r=.'~....~",:,,:..J.iS.~.-.;¿~...,~~..~...: .. /Y) ~ I ~/~ ~J0 ~~ \\ Q.1 \ ¡ ¡ ¡ .I i :>~'<::': . . '.-/ --- ! l':d!:':~:-~~'Ù', ~ ~.~¿,-/-~':i~ "'\:f:~"";J" f' ;. ,!. -,.! - :.! P.;J" "'t'r:H~ i~\,:~.~ç.:7~;\r~'~l ~/L~/"l/ :! Jo . rman aniel T. Seamount Jr ~ .", !'!. ~ ;.!...ct ~¡ -':('~"~-;;\";';ii'''~'' H ¡ . . . ,. ~: \,t 1, ~ t? : 1. 'i¡ ~~-+:,::t,';\,~{,- p / hærman COmmlSSloner'~ '-.j, 1},.~ t!.~ -:.,!,j l:.~;;~,:,~>_'~';i~ :~ if; \~~~El~~~~r~~~ ~' ~--1T¡¡' ..~Œ[- \'\: ~: \ ð f . ~. ¡ \ f ¡ , L): LJu=uU [ ) fruin' . fl. " l i ~U ) 'Ii Ii\\ ~ 1rK\' fÆ~' \Il IU¡~)U'\ L1 I :. billJ CQ.; I ù ' / / / FRANK H. MURKOWSKI, GOVERNOR AI/ASHA. OIL AND GAS CONSERVATION COlWlISSION 333 W. PH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907).279-1433 FAX (907) 276-7542 January 14, 2005 Mr. Gil Beuhler GPB Waterflood Resource Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Beuhler: This replaces the Administrative Approval that was issued on December 22, 2004. The only substantial correction is in the last sentence, which corrects the date that BPXA is to provide written documentation to the Commission of the results of the Pilot Operations. Sincerely, ..-~~ . -'\ vL- " ('..--)! I .~-~; '6d;..,~~C-~ÖVJ . j Y J .~ok).Ihbie Special Staff Assistant Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 81 0 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 1.3557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 Various AA's ) ) Subject:VariousÂ'A's From:. Jody..Colombie .<jody_colombie@admin.state.ak.us> Q~te:Fri,14Jan2005 .16: 19:21-0900 T9:tÙ:l<i~s~lþ~~(j7re~~Piijnts;; ~(Jc:Çyri.tbJ.~BMciv~I'<::bren - mciver@admin.state.ak.us>, Robert E Mintz ",%føþert---1Ï.1ìnt*@lå\y\st~téi~k.US>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbl~tl@bp.C()m> ~...S()ndiaSteWl11an<::Stc"\VÏÏlaSD@~P;Cpth>,Sçott&Câriitriy Taylor <staylör@alaska.Ï1et> ,stanel<j<:staÏ1ekj@W1()cat~ol11>,. e<;öláw <ecol~w@tl'U~tij~s.org:>,. ro~erågs<ial~ <fþseragsdale@gcLllet>,. tnnjr l-<:~l111jT l@aoLcom>,jbri<i<ilé<jbriddle@mara-thonoiLçolTI::>, sh~I1.eg <sbtill~g@evergteengas;c()ßþ:>,j dårlingtol1 <jdarlington@forestoil;com>;. nelson <kïielsdt1@petroleurimêws.çom>, cboddy <cboddy@usibelli.com>, Mark Dalton <:lIl~rk.dalt()n@hdrinc.coßþ:>,Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. \VQrc~st~r~'<:mark. p.worce$~~t@conocophillips.com> ,Bob <bob@inletkeeper.org>, wdv 5Wd;\T@ðjlt.~ta~~.*.1l$:>, tjf-<:tjr@Øw ~sta-t~'.*'ll~:>' þbritclI<:bbritch@alaska.net} ,trljl1~ls()11 <llljllelso11@pliryil1gertz;coth>; ClIarlesLQ'Dorriiell<cha-des.o'dönrlell@veco.êoth>,"RandYL. Skillèm"<:SkilleRL@BP . com>, "I)eQPÏ'M J; Jon~s"<:JöÏJ,e~PQ@BP.cotri>, "PaulG . Hytitt" <hyattpg@BP.c~m> ~"Ste\TenI{.Rq~sberg"<::I{os~beI{S@BP.colTI>,Löis <lois@illletkeeper.org>, DanBross<:kuacnews@kuac.qrg>, GordonPospisi1<:pospisQ@BP .C0111>, "Frallëis S. Sommer" <~Òn:urierES@J3:P .c()l1l?-,Mi~el ~.chultz<Mil<e1.S~h4Itz@BP.com>, . "Nick \V. Glover" 5Glover~\V @J3P .coffi>,"Paryl JrKleppin" <:K1eppi])E@BP .êþth>,"J~net P.Plattit <:J?:låttTP@:sP.cotn?;"RosárriieM..Jaçpþsen"<JacobsRM@BP .com>, ddollkel <4<iprrlf~1@cfl.IT~qol11:>,Çollìl1sM:P'U!lt<:çQll¡l1s~rp.ql1l1t@r~yeIl1l~~.~tale~ak. ty;>, mckay >JJ1èkay@gci;neþ,Barbarä.J?FuI1l11er..<barbara~f~fuHh1~r@ç()11()cophiUipSlCOrp.::>,.bqcast~f <bpcastWf@bp.coI1l>, ÇlIarlesBarker<barl<ér@l1sg~.g{n¡>,'. dOl1g---sçhultze >dòUKiSchultz~@xtoenergy ..com> ,J-I~nkAJford <hank.alford@exxomnqbiLco111>,MarkKQyac <yesllO l@gcLnet>, .gspfoff<gspfoff@aur{)rapower.cbtn>,GreggNady .<gt~gg;nady@shelLcom>, Fr~~ .Stë~ce <fred.steece@state.sd.us>;. rC170tty <:17crotty@ch2.l1l.com>,jejones <jejones@aurorapowe~.col11>, ..~ap~<:<iap~@alas~a;net>;jrþderi~k .<jroderick@gcLnet>, eyancy <:~yapêy@~eal-tite~llet>,nJ(}tIlesM. .Ruud"<Cjarhés.fu.Î1.Ùid@collÒcöphillips~çQI1l?-;... BritLiy~ly 811apala~k:a@ak;ri~t:?'/jah RjM@dgr.stat~.~~.tis:>, Kurt E Olson <kurt_olson@legis.state.a~.us>, bliplloJe.<Qllo11pje@bp.cöl11>,.. Mark Hanley<marl<---hanley@allad:l1"k()~cöl11>;..lorel1---h~trlan <loren_lemaÏ1@gov.stat~.akus>, JlllieHpule .<Cjulie _houle@dIlf.state.ak.us>, JqhïlW Katz <jwkatz@sso.org>, .Suzan J <Hill <suzan - hill@dec.stilte.alcus>,. tablerk <tablerk@unocaLcom>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak. us>,. bpöpp <bpopp@borough.kenaLai<.us>, JÙ1lWhite <jirp.white@satx.rr.com>,itJohn. S. Haworth" <john.s;haworth@exxonmobil.com> ,marty <marty@rkindustrial.com>, ghammons <gh.átrll11011s@aol.com> ,I11lclean. <nnclean@po box.alaska.net>~ 111,km720Q <111,km7200@aoLcorp.>, BrianGillespie <ifbtng@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com> , Todd Durkee <TDURKEE@KMG~com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne.Rancier <RANCIER@petro-canada.ca>, Bill Miller <Bill_Miller@xtoalaska.com>, Brandon Gagnon <bgagnon@brenalaw.com>, PauIWinslow.<pmwinslow@forestoi1.com>, Garry Catron <catrongr@bp.com>, Shannaine Copeland <copelasv@bp.com> ,Kristin Dirks <kristin - dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marath.onoiLcom>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill - Fowler@anadarko.COM>, Vaughn. Swartz <vaughn.swartz@rbccm.com>, Scott Cranswìck <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, SteveLambe<lambes@unocaLcom>,jack newell <Cj ack.newell@acsalaska.net>, Jatrles Scherr <James.Scherr@mms.gov>, david Toby 10f2 1/14/20054:19 PM Various AA's ) ') 2of2 1/14/20054:19 PM ffi1~')~~~~~~ FRANK H. MURKOWSK/, GOVERNOR AI,ASIiA. OIL AND GAS CONSERVATION cOlWlISSION 333 W. 7TH AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRA TIVE APPROVAL NUMBERS C0457 A.OO4 and AI022B.OO2 Mr. Gil Beuhler . GPB Waterflood Resource Manager BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Beuhler: By letter dated December 6, 2004, BP Exploration (Alaska), Inc. ("BPXA") requested authorization to extend current pilot miscible injection (MI) operations in Aurora Oil Pool ("AOP") Wells S-112, S-110 and S-116. Approval was given by the Commission on May 11 for pilot operations through December 31, 2004. Due to operational delays and low injection rates, only S-ll 0 has been on miscible gas injection, and only 1/3 of the total miscible injectant volume planned for the pilot has been injected. You've stated that, with favorable conclusive results from the pilot, you will apply for a larger scale project. The Commission finds that the requested change will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater The Commission approves continuation of Ml injection through September 30, 2005 into AOP Wells S-112, S-ll0 and S-ll6, subject to the conditions, limitations, and requirements set out in AlO 22B and CO 457 A and statewide regulations under 20 MC 25 (to the extent not otherwise superseded by AlO 22B and Conservation Order 457 A). It is a condition of this approval that BPXA provide written documentation of the results of the pilot no later than October 31, 2004. age, Alaska and dated December 22, 2004 Zf~ ~ Daniel T. Seamount, Jr. Commissioner Orders Subject: Orders From: Jody Colombie <jody - colombie@admin.state.ak.us> Date: Thu, 23 Dec 2004 06:52:48 -0900 To: undisclosed-recipients:; , , BeC: Robert E Mintz <robert_mintz@law.state.ak.us>, Christine Hansen <c..hansen@iogcc.state.ok.us>, Terrie Hubble <hubblêt1@bp~com>, Sondra Stewman <8 tewmaSD@BP.com>, Scott & Cammy Taylor <staylor@alaska.net>,. stanekj. ., , <stanekj@unocal.com>, e~olaw <ecolaw@trustees~org>, tosenigsdale <;:roseragsdale@gci.net>,.trnjrl <trmjrl@apl.coni>, jbriddle <jbriddl~@marathonóil.com>, rockhill <rockhill@aoga.org>,shaneg, . <shaneg@evergreengas.com>, jdarIington <jdarlington@f()restoil.com>,. nelsQn .' , <knèlson@petroleumnews.com>, 'cboddy <:cboddy@usîb~lli.cö.m>, Mark Dalton, , , <mark.daltQn@hdrinc.com>, Shannon Donnelly <:shannon.donnelly@conocophillip~.co111>, "Mark P. Worcester" <mark.p.worcester@,conocophillips.com>, Bob. <bob@inletkeeþer.òrg>, wdv <wdv@dnr.state.ak.us>, tjr <tjt@dnr.state.åk..us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <c~ailes.otdonnell@veco.com?,.. "Randy L. ' Skillernft <SkilleRL@BP.com>, "DeborahJ. Jones" <JonesD6@BP.com>, "PaulG.Hyatt'¡ . <hyattpg@BP ..com>, "Steven R. Rossberg" <RossbeRS@BP:.com>, Lois <;lois@itiletkeeper~org>, DanSross <k:uacnews@kuac.org>, Gordon Pospisil <PospisG@BP .com>, "Fr(Ulcis S. Sommèr" . <SommerFS@BP.com>, Mikel Schultz <MikeI.Schultz@BP;com>, '''Nick W.Glover~' <q-IoverNW@BP.com>, "DaryIJ.Kleppintl <Kl~ppiDE,@Bf.com>, "Janet D. Platt" <PlattJD@BP.corri>;'''Rosanne:M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, Collins Mount <collins - mount@revenue.state.ak.us>, mckay . ' <ni~kay@gci.net>, Barbara FFuItmer <:bàrbara.£fullmer@conocophilIips.com>,: bocastwf .. <bocastwf@bp.com>, Charles B~ker<harker@usgs.gov» doug_ß~hultze ' " "... " . <doug_schu1tze@xtoenergy.coin>; Hank Alford <hank.alford@,exxonrnobil.com>"Mark Kova~' <y~sno 1 @gci.net>, gspfoff <gspfoff@auro~apower;com>, Gregg Nady <gregg~nady@shell.~orn>' . Fred Steece<fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones ..'... <jejones@aurorapower.com>, dapa <dapa@alaSka~net>, jroderick <jroderick@gci.net>:,eyaney , <eyancy@seal-tite.net>, "lames M. Ruud" <j~es~m.ruud@conocophilIips~com>, :arit Lively <mapalaska@ak.net>, jab <jah@dnr~state.ak.us>; Kurt E' Olson <kurt- olson@legis.state.ak~us>, bu~noje <buonojé@bp.com>,Mark Hanley <mark~hanley@anadarko.com>, loren ~leman' . <loren_leman@gov.state.alcus>, Jp.lie Houle ~ulie--houle@dnr.state.ak.us>, John 'Vi, KatZ , <jwkatz@ssp.org>, Suzan J Hill <suzan - hill@deC.state~ak~us>; tablerk <tabl~rk@unocáI.~oni>, Brady <brady@aoga.org>,~rianHavelock<~e4@dr1r.stàtè.åk.us>{bpopp '. . ':' '. <bpopp@borough.keniú.ak.us>,.Jim White <jimwhite@~tX~IT .com>~ n John S. Haworth" <john.s.haworth@exxonniobíl.com>,'marty <mart)f@rldndùstrial.com?, ghaIÌ1mo.ns. , ',. . <ghamm()l1s@aol.com>, rn1clean', <rnicleå.n@pQbo~.alaska..het>,mkm 7200 <mkm7200@aol.com>, Brian Gillespie' <ifbmg@uaa.alask~edu>, David L'BòelenS<7=qboelens@aurorap<)wer.com>, Tödd' . Purkee <TDURKEE@KMG.com>, 'Gary Schultz <gåry:..ßchultz@<lnr.s.tate.ak.ll~>,Wayne Rancier <RANCIER@petro-ca.n~da.ca>~ BillMill~r <~j~~Miller@~t9~aSl<~coni>, ,BrandQ~ 9agnon, " <bgagnon($br~na1aw .com>"Patll\Vinslow <PJ1lw~lo~~~~reStoil.c~II1>" Garryqa~~n, <~~trongf@bp.cOÌIl>, ~lwînaineCopëI~d:<copel~v@bp~éÖm>,I<ristin pirks " , . " <kristin - dirkS@dnr.state:~akus>;cJ(aynell.ZenuUl<kjz;è~àn@m~ath()nòil.com>, JòhnTower <John. T ower@eìa.doe..gpv>, Bill Fowler <Bill_Fo\Vler@anadarkQ~COM>,V anghn Swartz <vaughn.swartz@tbccm.còm» Scott .Cranswlck <sCott.cranswick@nims.gov>, Brad'McKim <mckimbs@BP ~com>" . Steve Lambe <lambes@unocal.com>, jack newell .'. <jack.newell@acsalaska.net>, James Scherr <James.Scherr@mms.gov>, david roby 10f2 12/23/2004 6:53 AM Orders 20f2 <David.Roby@mms.gov>, Tim Lawlor <Tim_Lawlor@.ak.blm,.gov>, Lynnda Kahn <Lynnda - Kahn@fws.gov>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, Jerry Dethlefs <n 1617@conocophillips.com>, Cynthia B Mciver <bren _fficiver@admin.state.ak.us> -- . . . ".. ~ --~------ ': . ; Content-Type: application/pdf.! .C0457 A.OO4.pdf ¡ . .... ' ¡ -----~- ---- --~~_: C~~~~nt~_~~c?di~g: ~:se6~ ---~-,---~! ,-------'_..~-~ --'.'..__._--------_.--:-------:----'--;------;-----:-,-:-;-------:------:---------- . ~... .. n. "' .~.. .. ~. ,... ~ '. _'n ..... . ,'Content-Type: applicationlpdf. ,C0543.pdf' ':. . . ..: . , .: :: Content-Encoding: base64 ... ~.. ".' .'-'..- n " ... hr. ... n n' ~ ~.. ......~,- . ... ...~... ,. ". . n_n . - . .m .~-".,'" '...n'~_.~'~,., 12/23/20046:53 AM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 ) Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb IHS Energy Group . GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage. AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 11ft//? ~ I~C¡ ~q ::J:t: w BP Exploration (Alaska), 1..,-,. 900 East Benson Boulevard Post Office Box 196612 Anchorage. Alaska 99519-6612 Telephone (907) 564 581 ) bp December 6, 2004 Jane Williamson ...Bob Crandall Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 ~chorage,AJ( 99501 RECEIVED DEC 0'82004 RE: Aurora EOR Pilot extension Alaska Oil & Gaa Cons. Commission Anchorage We respectfully request permission to extend the current EaR pilot for Aurora injection wells S-112, S-110, and S-116 until June 30, 2005. The extension beyond 2004. is needed to complete the originally proposed pilot and allow the project to be bridged until a full- field EaR expansion can be applied for and approved next year. Due to operational delays and low injection rates, only S-110 has been on miscible gas injection with 30 of the proposed 90 MMSCF injected to date. Based on results so far it is clear that 3 months injection into each well will be required to fully evaluate each of the pilot wells. Please call Jim Young 564-5754 if you have any questions. Sincerely, ~~~~ Gil Beuhler GPB WEST Manager Attachments CC: Mark Vela (ExxonMobil) Dan Kruse (CP AI) Bradley Brice (Forest Oil) Steve Wright (Chevron-Texaco) 2 BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 · Telephone (907) 564581 g~ bp ~ .~ . ~ April 26, 2004 Jane Williamson Bob Krandall Alaska Oil and Gas Conservation Commission 333 West ih Avenue, Suite 100 Anchorage, AK 99501 RE: Proposed Aurora EOR Pilot In order to enhance water injection rates and fine-tune enhanced oil recovery benefits, a 4 to 6 week pilot is proposed for Aurora injection wells S-112, S-11 0, and S-116. Attached, are details and supporting info for the proposed test which will help to provide justification for full EOR expansion into 2 new areas within the Aurora field. Please call Jim Young 564-5754 if you have any questions. Sincerely, ~~ Gil Beuhler GPB Satellites Manager Attachments CC: Mark Vela (ExxonMobil) Dan Kruse (CP AI) Leonard Gurule (Forest Oil) Steve Wright (Chevron-Texaco) (~ o~ PH Y RECEIVED APR 2 8 Z004 Alaska Oil & Gas Cons. Commission Anchorage SCANNED JUL 1 5 2004 '- ~ ~; 2004 Aurora MI Pilot Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507 Description of Operation Tertiary EOR Miscible Water Alternating Gas (MW AG) started in the North of Crest (NOC) and West blocks at Aurora in December 2003. Expansion of MW AG to other areas of the field is dependent upon performance of primary production and waterftood operations, and is anticipated in 2004 for the Southeast Crest (SEC) and Crest (CR) blocks. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil and increases as the Miscible Injectant (M!) reduces residual oil saturation around the injection well. In order to increases injection rates and verify long-term feasibility, pilot injection of MI into the SEC is proposed to begin in May 2004 using injection wells S-llOi and S-1l2i. CR injection is proposed to begin in August 2004 using injection well S-116i. Geologic Information The Geology of the AOP is described in Section I of the Pool Rules application. Mechanical Integrity of Injection Wells Wells S-llOi, S-1l2i, and S-1l6i been completed in accordance with 20 AAC 25.412, thus satisfying mechanical integrity requirements. Refer to AIO for offset penetrations within 1,4 mile of well S-1l2i, 10-403 application for well S-llOi, and drilling permit for S-116i. No new wells have penetrated the proposed injection interval since this information was last provided. Injection Fluid Type/Source/CompatibilitylPressure/Confinement Refer to AIO 22A application. M' MI d Maximum Injected Rate t h 11· h "1 d [,11 axImum rates an vo umes or eac we III t e plot are estImate as o ows: Pilot StartUp Cum WI Est. Radius of MI Est. Inj MSTB MI rate Press > volume days on Well Date (at S U) MSCFD MMP (ft) MMSCF MI S-llOi 5/15/04 240 3,000 500' 90 30 S-112i 5/15/04 250 4,500 500' 135 30 S-116i 8/15/04 150 4,500 500' 90 20 - ------ - Pilot Surveillance Plan Injection rates and pressure response will be closely monitored to assess level of improvement during and after the MI cycle. An increase of injection ratt's that ~]ow a 1 :~~ I~ ~ VRR > 1 to be obtained is the goal, and a pressures in the injectors as well as the offset producers will be obtained and analyzed to verify results. Analysis of Reservoir Pressure Surveys within the proposed Pilot areas Two pressure maps covering the proposed pilot area wells are shown below. Refer to 2003 ASR for details on pressure surveys and analysis. 599000 598500 598000 605000 610000 615000 620000 625000 Figure 1 Simulation based dymamic pressure map, psig at 6700' ss AOP datum, April'04 599000 598500 598000 3300 3000 2700 2400 605000 610000 615000 620000 625000 Figure 2 Static Pressure map with last SBHP date, psig at 6700' ss AOP datum SCANNED JUL 1 5 200~ 1 bp ,~ ~ BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage. Alaska 99519-6612 (907) 561-5111 April 28, 2003 Sarah Palin, Chair Randy Huedrich, Commissioner Daniel T. Seamount, Commissioner Alaska Oil and Gas Conservation Commission 333 West ¡th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Rehearing - Area Injection Order No. 22A Response to Proposed Amendment of Conservation Order No. 457 Aurora Oil Pool - Prudhoe Bay Field Dear Commissioners: Pursuant to AS 31.05.080(a), BP Exploration (Alaska) Inc. (BPXA), as Operator of the Aurora Oil Pool (AOP) on behalf of the Aurora Owners, timely submits this application for rehearing of Area Injection Order 22A (AIO 22A) issued by the Alaska Oil and Gas Conservation Commission (the "Commission") on April 3, 2003 and responds to the Commission's April 3, 2003 notice of public hearing concerning the Proposed Amendment of Conservation Order No. 457 (CO 457) and the Proposed Revocation of Conservation Order No. 98-A (CO 98-A). BPXA respectfully submits that approval of its application for the amendment to AIO 22 is essential to enhancing ultimate oil recovery within the AOP. BPXA hereby supplements the record in response to the above matters and requests that Attachments 1 and 2 to this rehearing application be maintained as confidential pursuant to AS 31.05.035(d). This material is not information that is required to be submitted under AS 31.05.035(a), and contains trade secrets and engineering, geological and other information, and interpretations thereof. BPXA initially addresses and responds to Area Injection Order No. 22A, followed by comments in response to the proposed amendments to Conservation Order No. 457. RECEIVED APR 2 8 Z003 Alaska Oil & Gas Cons. Commission Anchorage SCANNED JUL 1 5 2004 ~ ~ Application for Rehearing - AIO 22A 4/28/2003 Page 2 I. Response to Area Injection Order No. 22A A. Backqround On December 9,2002 BPXA requested an Order from the Commission modifying Area Injection Order No. 22 to authorize the underground injection of miscible injectant ("MI") for enhanced oil recovery in the AOP. On March 4, 2003 the Commission conducted a hearing on BPXA's request and on April 3, 2003 issued its decision denying the request (Area Injection Order No. 22A) without prejudice to BPXA's right to renew the application at a later date. The Commission's April 3, 2003 Order indicated that the Commission felt certain issues were outstanding. BPXA hereby responds to the Order and supplements the record with the materials and information concerning AOP well pressures and additional information on the current reservoir management plan, including depletion strategy, which is contained herein and in Attachments 1 through 4. BPXA believes this material provides a more comprehensive understanding of AOP reservoir pressures and depletion strategy than is indicated by certain findings and conclusions contained in the Order. Before addressing the conclusions contained in AIO 22A, BPXA provides the following information related to certain findings by the Commission. B. Response to Certain Findinqs in AIO 22A 1. Operators/Surface Owners (20 AAC25.402(c)(2) and 20 AAC 25.403(c)(3)) This paragraph should be updated to reflect the current PBU and Aurora aligned Working Interest Owners as follows: BP Exploration (Alaska) Inc. ExxonMobil Alaska Production Inc. ConocoPhillips Alaska, Inc. Chevron U.S.A. Inc. Forest Oil Corporation 6. Injection Fluid and Rates (20 AAC 25.402(c)(9)) a.) Additional Source Water AIO 22A does not anticipate the potential that exists for using source water that may be obtained from the Prince Creek Formation in the SCANNED JUll 52004 ~, ~ Application for Rehearing - AIO 22A 4/28/2003 Page 3 GC-2 area from dedicated source water production wells and used for injection into the AOP. Based upon Milne Point experiences, compatibility between the source water and the AOP Formation fluids will not be an issue. We therefore request that the Order also authorize the injection of Prince Creek source water. The following table depicts Prince Creek source water chemistry profiles from Milne Point source water wells. Well Units MPB-1 MPCFP-1 Sodium mg/I 1046 1083 Calcium mg/I 138 96 Magnesium mg/I 11 19 Barium mg/I 10 4 Chloride mg/I 1800 1820 Sulfate mg/I 4 0 Carbonate mg/I 0 0 Bicarbonate mg/I 151 140 Total Dissolved Solids mg/I 3160 3162 b.) Other Fluids AIO 22A also does not anticipate the possibility that fluids other than MI and water may be injected into the AOP at some future date during the life of the project in order to enhance recovery of oil and gas. We therefore request that the Order also authorize the injection of: 1. Solution gas associated with oil production - reinjected for reservoir pressure maintenance. 2. Tracer survey fluid - to monitor reservoir performance. 3. Non-hazardous water collected from PBU reserve pits, well house cellars and standing ponds. 11. Hydrocarbon Recovery and Reservoir Impact (20 AAC 25.402(c)(14)) Finding 11 does not capture the current technical understanding and development strategy for the AOP, which we are setting forth herein to provide context. SCANNED JUL 1 5 2004 -- r--, Application for Rehearing - AIO 22A 4/28/2003 Page 4 Recovery Mechanisms Evaluation of hydrocarbon recovery mechanisms for the Aurora Oil Pool has been the subject of ongoing analysis. The technical characteristics of considerable faulting, low initial oil rates, gas cap presence and thin oil column indicate a phased development program is appropriate and will maximize ultimate recovery. Phased development of the AOP employs three reservoir mechanisms over field life. Initial development involves a period of primary production to determine reservoir periormance and drainage areas. Primary production under solution gas and aquifer influx drive from both floodable and non-waterilood pay intervals provides information used to improve the depletion plan, including production pressure data to evaluate compartmentalization and conformance. This drilling and surveillance data influences the next steps in reservoir development, including proper injection pattern layout. In areas where injection is indicated, secondary water flood is initiated to improve recovery by reducing residual oil saturation and maintaining well productivity via reservoir pressure support. Water injection should be initiated to maintain average reservoir pressure above 2400 psi in the flood area to ensure recovery targets are achieved. Tertiary EOR MWAG (miscible water alternating gas) provides additional oil recovery by further reducing residual oil saturation via injection of miscible gas alternating with water injection. In addition to enhancing oil recovery, injection of miscible gas provides additional reservoir benefits (Attachment 2). Slim tube study and compositional modeling indicate the Aurora reservoir fluid miscibility pressure with the Prudhoe Bay miscible gas supply is 2700 psi. Miscible gas injection will be operated to maintain miscibility between the reservoir fluid and the injected miscible gas. There will be higher pressure around injection wells and a pressure sink around the producers, which, in some cases can be below MMP. It is common practice in EOR projects to maintain pressure below MMP in the area of the producers due to several reasons: a) The low-pressure region around the producers is of generally small pore volume relative to the flooded area pore volume. This occurs for two reasons, both related to radial flow: first the pressure profile drops in a non-linear fashion near the wellbore (depending on skin) and secondly, pore volume is a function of the radius from the wellbore and increases at a rate proportional to .-2. The variables determining the steady state pressure distribution in the reservoir include injection pattern geometry, formation permeability, formation SCANNED JUL 1 5 2004 .--., ,/'""'... Application for Rehearing - AIO 22A 4/28/2003 Page 5 heterogeneities, injector and producer skin damage, maximum allowable injection pressure, and artificial lift method and efficiency. b) Maximum sweep efficiency occurs in most reservoirs when producing bottom-hole pressure is minimized, increasing the contribution and sweep of low permeability intervals. Analysis of the miscible displacement mechanism that has been periormed shows that additional oil recovery by the miscible displacement mechanism is evident in all cases studied (Attachment 2). With average reservoir pressures above the MMP, incremental EOR recovery is essentially the same even though producer region pressures below the MMP are maintained. As a consequence, reservoir management guidelines for EOR should be based on average reservoir pressure rather than producer pressure. Early implementation of the secondary and tertiary injection processes allows adequate time for producers to capture mobilized oil. Proper field management includes monitoring of productivity, GOR, water cut, pressure, of injection voidage replacement ratios and other measurements. Reservoir data gathering employed in AOP development includes: 1) an Aurora seismic survey in the year 2000, 2) basic and enhanced well log data gathering, 3) whole and sidewall core analysis of reservoir properties, 4) a single-well chemical tracer test for initial oil saturation, residual oil saturation to water, oil-water fractional flow, and residual oil saturation to miscible gas injection, 5) well flow and pressure tests, 6) suriace and subsuriace PVT sample gathering, 7) black oil PVT experiments, and 8) slim tube miscibility experiments. Data gathering combined with early construction of the reservoir framework and appropriate evaluation tools has been employed by a multi-disciplinary team to insure proper field management. The quality of the six types of pressure data measurements taken at Aurora have been reviewed and ranked according to accuracy. Two of the data types require corrections for insufficient shut-in time and one for wellbore pressure gradients. These corrections and the resulting pressure database are shown in Attachment 4. To determine current field average pressure, these well data are integrated with a reservoir simulation model. The Aurora field average reservoir pressure is 3142 psi as of April 2003 (Attachment 2). SCANNED JUL 1 5 2004 .or-- ~, Application for Rehearing - AIO 22A 4/28/2003 Page 6 A high quality of match between field data and the reservoir model is evident in well-level comparisons of predicted versus measured pressures. Field Development Field development areas for the AOP have been defined by geological and reservoir pertormance data interpretation. Differing initial gas-oil and oil-water contacts and pressure behavior during primary production led to the definition of these field development management areas. These areas include the: 1) West Area (comprised of the previously separated V-200 and Beechey Areas), 2) North of Crest Area, 3) South East of Crest Area, and 4) Crest Area. An effective water injection flood has been established in the West and North of Crest areas providing pressure support and reducing residual oil saturations. Other development activities include: 1) Initiating water injection into the South East of Crest area with the pending conversion of pre-produced injectors 8-110 and S-112 to injection. 2) Crest area production began in mid-March 2003 with startup of Aurora well 8-115; well 8-117 production startup is imminent. These wells' primary production pertormance and other well data will be considered in the evaluation of drilling a supporting injection well, i.e. the potential 8-116 well. 3) Evaluation of a local water injection booster pump to increase water injection throughput rates by raising the available Aurora wellhead water injection pressure. Finally, an Aurora field development case history was published in the May 2002 SPE paper 76739, "Proactive Surveillance And Phased Development Yields Promising Results From The Aurora Field 30-Years After Discovery" (see Attachment 3). This paper discusses development learnings and plan modifications made to "improve rate, increase reserves, and meet economic hurdles." C. Response to AIO 22A Conclusions The paragraph numbers below correspond with the numbered Conclusions in AIO 22A. SCANNED JUL 1 5 2004 ,-- /' Application for Rehearing - AIO 22A 4/28/2003 Page 7 1. The AOP average reservoir pressure is currently 3142 psia. The Minimum Miscibility Pressure (MMP) is 2700 psia, with 90% of the field area above MMP. Areas below the MMP are limited to the producing well areas and as discussed above, low pressures near producers are expected and are consistent with mechanistic simulation models that show incremental oil recovery due to the miscible displacement enhanced oil recovery mechanism. As a result, the proposed injection of fluids will act to enhance recovery and is an integral part of the AOP Plan of Development as outlined in the response to Finding 11. 2. Concerning current reservoir pressures and MMP, all areas of the AOP are of sufficient pressure for initiating an MW AG process, beginning in the West and North of Crest areas. In the South East of Crest area where water injection has not yet begun, the current reservoir pressure is also far above the MMP. Initiating water injection in the S-112i and S-11 Oi wells will restore near-wellbore area pressure that declined during pre-production. 3. Current development plans and development strategy are fully consistent with testimony provided to the Commission in support of CO 457 and AIO 22. Testimony and analysis provided to the Commission in support of CO 457 indicated thatprimary production would be employed initially and that primary production less than 18 months would not jeopardize ultimate recovery. Updated information using current field evaluation tools, an updated reservoir description and the wells drilled in support of field development indicates that average reservoir pressures down to 2400 psi during primary production do not substantially impact ultimate recovery. This pressure corresponds with 24 months of primary production with full well density at startup; while field development has not occurred as rapidly and involves staggered production and injection timing. The current field pressure of 3142 psi is well above the limits established by these analyses. Water injection startup in the field was initiated within the 18- month period indicated to the Commission in support of CO 457 and AIO 22. Field development and operation are being conducted in a manner consistent with sound engineering and geosciences practices and with CO 457 and AIO 22. With Commission approval of the modifications requested by the Operator to AIO 22, including increasing to the maximum allowable surface water injection pressure and to allow the injection of EOR miscible gas injection, AOP oil recovery will be maximized. 4. Regarding cumulative voidage, voidage calculations made by the Commission used gas rate data that included artificial lift gas in the scANNeb JUL 1 1) 2004 ,,,-.., /". Application for Rehearing - AIO 22A 4/28/2003 Page 8 calculation, whereas the calculation should have been made using data that excluded artificial lift gas volumes. This may have occurred because BPXA volume accounting for November 2002 through February 2003 in wells S-102 and S-105 did not differentiate gas lift gas from formation gas. The combined total lift gas for these two wells, approximately 4,000 equivalent reservoir barrels per day, should not be included in the void age calculation. BPXA has now reconciled this information with Commission staff. As shown in Attachment 1, over 90% of AOP voidage to date has occurred in the West and North of Crest areas that currently have a VRR greater than 1.0. In the South East of Crest area water injection startup is imminent with the two pre-produced injection wells, S-11 0 and S-112, shut-in for conversion to injection. In the Crest area, production voidage began in March of 2003 and continued primary production is necessary to determine drainage areas and injection plans consistent with the Aurora development plan described above in the response to Finding 11 included in Section B. 5. BPXA'scurrent reservoir management strategy is discussed above and additional details are attached. 6. Current reservoir pressure and incremental EOR recovery are discussed above, with additional data regarding current average reservoir pressure set forth in Attachments 1, 2 and 4. 7. Regarding additional well pressure measurements, the plan for acquiring additional well pressure surveillance data is included in Attachment 1. This plan addresses field-wide and area specific pressure data gathering in order to insure proper field development and operation. II. Notice of Public Hearing - Proposed Amendment of CO 457 The paragraph numbers below correspond to the proposed amendments to CO 457 included in the Commission's April 4, 2003 Notice of Public Hearing. 1. BPXA agrees that CO 457 should contain a definition of the AOP, as follows: "The AOP is defined as the accumulation of oil that is common to and correlates with the accumulation found in the interval between 6765'and 7765' measured depth in the Mobil Oil Corporation Mobil- Phillips North Kuparuk State No. 26-12-12 well." SCANNED JUL 1 5 2004 ,r--- ~ Application for Rehearing - AIO 22A 4/28/2003 Page 9 2. BPXA agrees that Conservation Order 457 should be revised to recognize the applicability of the PBU Western Satellite Production Metering Plan as described and adopted by the Commission in CO 471. 3. BPXA does not believe Rule 5 should be specifically modified as the Commission is considering. Continued production of all Aurora producers is consistent with the AOP development plan as described above and is necessary to maximize economic recovery. Surveillance pressure data gathering is planned for the field as described in Attachment 1. 4. BPXA does not believe Rule 7 should be specifically modified as the Commission is considering. The miscible gas injection project at Aurora will be operated to maintain the flood with an average reservoir pressure that insures miscible displacement recovery is achieved. 5. BPXA recommends that Rule 8 of Conservation Order No. 457 be revised to add the following: g) Review of Annual Plan of Operations and Development, includinq discussion of the reservoir depletion plan and the status of reservoir repressurization activity. As demonstrated in the information submitted in support of AIO 22A, as supplemented herein, the Aurora field development plan promotes greater field ultimate recovery under waterflood and miscible gas EOR injection. The planned miscible gas injection project will recover a significant incremental amount of oil over and above the expected waterflood incremental recovery. III. Summary BPXA respectfully requests that the Commission reconsider AIO 22A and grant this application for rehearing. BPXA has addressed herein the findings and conclusions that should be reconsidered and has submitted additional information for the record to address the issues raised in the Order. We believe the additional information provided demonstrates that because of the reservoir quality and fluid contact risks at Aurora, implementation of the development strategy as proposed is essential to enhancing ultimate oil recovery within the AOP. Further refinement of our understanding of the AOP and adjustments to the development plan highlight the need to accelerate EOR start-up. The surveillance plan and additional well pressure information should resolve the concerns expressed in AIO 22A. SCANNED JUl 1 4) 2004 .~ .~ Application for Rehearing - AIO 22A 4/28/2003 Page 10 Therefore, we respectfully request that, based upon the additional information, the Commission withdraw and void the April 3, 2003 AIO 22A decision and issue an Order approving BPXA's application for injection of enriched gas in the AOP and for an increase in allowable water injection pressure. In addition, we conclude, as discussed herein, that several of the proposed amendments to CO 457 are unnecessary or should be revised as indicated herein. BPXA is prepared to have the Commission rule on the basis of the record as supplemented herein and without further public hearings, unless the Commission's concerns have not been resolved by the information supplemented herein. Please contact Gil Beuhler (564-5143) or Gary Gustafson (564-5304) if you have any questions regarding this correspondence. Maureen son Pertormance Unit Leader Greater Prudhoe Bay Attachments: Attachment 1 - April 17, 2003 BPXA Aurora Reservoir Presentation to AOGCC Attachment 2 - April 23, 2003 BPXA Aurora Reservoir Presentation to AOGCC Attachment 3 - SPE 76739 "Proactive Surveillance and Phased Development Yields Promising Results From the Aurora Field 30-Years After Discover" (J.P. Young, F.E. Bakun, F.K. Paskvan, SPE, E.H. Westergaard, BP Exploration (Alaska) Inc.). Attachment 4 - Aurora Representative Well Pressures (BPXA) SCANNED JUL 1 5 2004 "------. /~- Application for Rehearing - AIO 22A 4/28/2003 Page 11 cc: M. Vela, ExxonMobil K. Griffin, Forest Oil J. Johnson, CPAI G.M. Forsthoff, ChevronTexaco Francis Sommer, BPXA Gil Beuhler, BPXA Frank Paskvan, BPXA Rosy Jacobsen, BPXA Gary Gustafson, BPXA Mark Worcester, CPAI Steve Luna, ExxonMobil .......--..-. ". ..-.. "-'~-" . ........ SCANNED JUL 1 5 2004 ~~, ATTACHMENT 3 /", Society of Petroleum Engineers SPE 76739 Proactive Surveillance And Phased Development Yields Promising Results From The Aurora Field 30- Years After Discovery. (J. P. Young, F. E. Bakun, F. K. Paskvan, SPE), E. H. Westergaard, BP Exploration. Copyrighl2OO2. Society of PeIroIeum Enginee<s Inc. This paper was ~ for ..-Iation at ti1e SPE Westem RegíonaIIAAPG Pacific Section Joint Meeting held in Anchorage. _. U,SA. 2G-22 May 2002, This paper was _ for presentation by an SPE Program ~ -.g review 01 ìnIoIn'-. conIained in an _ submitIed by ti1e auIhor(l). Contents of ti1e paper. as ..-. have not been ...- by ti1e Society of Petroleum ~ and are IUbjecI to _ by ti1e -.0.(5), The material. as ~. _ not .-sariIy reflect any position of ti1e Society of PeIJoIeum Enginee<s. its office<$. or membenI. P-", presented at SPE ..-.go are IUbjeclIo publication review by EditOrial Committees of ti1e Society of PeIJoIeum ens;r-s. EIeàronic reproductiOn. distribution. or sto<age of any part of this paper for IXII'M*'âaI pwposes without ti1e _en consent of ti1e Society of Petroleum Enginee<s is ~, PermI&sion to reproduce in print is restricted to an _ of not more than 300 WOlds; illustrations may not be copied, The _ must contain conspicuous acknowledgment of where and by whom ti1e paper was presented. Write Librarian. SPE. P,O, Box 833836. RichanIson. TX 75083-3836. U.SA. fax 01-972-952-9435. Abstract Although three 1969 exploration wells discovered hydrocarbons in the Aurora structure, development was not possible until a scope change to the V-200 exploration well demonstrated commerciality 30-years later. Commencing in June 2000, an aggressive 6-well horizontal and vertical development/appraisal program yielded over 1.75 million barrels of oil in the first year and provided a better understanding of a reservoir previously thought marginally commercial. Investment in reservoir description and proactive surveillance led to accurate decision-making, and with innovations, yielded significant return from a "marginal" field. Introduction The Aurora Pool is located on Alaska's North Slope and produces from the Kuparuk River Formation. See location map, Figure I. Hydrocarbons were discovered in 1969 with three exploration wells: Beechey Point State # I, #2 and North Kuparuk 26-12- 12. Results from these wells, shown in table 1, did not give any confidence that commercial rates could be achieved from the field, and exploration work was minimal until 1999. The following key points were recognized from seismic data and exploration results: I) Severe faulting and compartmentalization with variable fluid contacts 2) Significant variations in reservoir pay thickness, quality, and mineralogy 3) Marginal quality, damage prone formation with gas-cap present. Table 1 Exploration Well Test Results Well (date) Gross Oil Oil GOR Estimated ~ ~ (scffstb) £!ill BPS#\ (\%9) 60' (+ gas) \8 >70,000 50+ BPS#2 (1969) 15' 0 0 50+ NKUP 26-\2-\2 30' 32 <700 50+ (1969) V -200 (1999) 58' 19]5 718 +\2 In 1999, a late scope change was made to extend the V-200 exploration well, a dry hole in the Schrader Bluff, to penetrate and test the Kuparuk. The V -200 encountered approximately 58' of oil column and was tested in four stages while progressively adding perforations up hole with a final production test rate of 1915 bop<! with a GOR of 718 scf/stb. By achieving commercial rates with the initial completion, V- 200 results unlocked development of the Aurora field. Due to Aurora's proximity with existing Ivishak Participating Area (IPA) infrastructure, an accelerated development path was taken. Instead of building a new development drilling pad centered on the V-200 well, which would require pipelines, power and access roads, the field was developed from the existing IP AS-pad. To date, ten development wells have been completed in the Aurora structure. The first three wells, located in the V-2oo fault block, were drilled horizontally to take advantage of the relatively large and continuous block. The eastern segments of the field have been developed with vertical fractured wells to access separate producing intervals. The western portion of the field was accessed with extended reach drilling technology and a single V-shaped injector that was drilled to provide water flood support to two discrete fault blocks. The Aurora reservoir description has matured significantly over the last 2 years. An enhanced 3-D seismic survey acquired early in 2000 improved fault resolution, a new sequence stratigraphic framework more accurately describes the geology of the structure and a single well tracer test was SCANNED JUL 1 5 2004 \....J 2 '-.,I J. P. YOUNG, F, E. BAKUN, F. K. PASKVAN, E. H. WESTERGAARD SPE 76739 utilized to improve estimates of connate water, residual oil saturation to water flood and residual oil saturation to miscible gas flood. Future development well locations will be based on the integration of the above, plus surveillance data from existing wells and continued 3D fluid flow simulation. This paper provides a development case history and discusses learnings made along the way. Structure Top Kuparuk structure in the Aurora area is essentially a northwest-southeast oriented antifonn broken up by north- south striking faults. Gentle slopes dipping 2.5 to 6.5 degrees characterize the northeast and southwest flanks of the structure. In contrast, rotated fault blocks characterize the southern and western flanks of the structure. A major north-south striking fault with up to 200 feet of down-to-the-west displacement effectively bisects the Aurora Pool area into an eastern half, which contains the S-Pad Sag River/Ivishak development wells, and a western half, which contains the V -200, and Beechey Point State 1. See figure 2 for a top of structure map showing various development blocks within the field. Stratigraphy The Kuparuk River Fonnation was deposited as deltaic and shore face to shelf sediments. The Kuparuk is composed of very fine to medium grained quartz-rich sandstone, interbedded with siltstone and mudstone. See figure 3 for the V-2oo type log. The uppennost unit, the Kuparuk C interval, contains the primary reservoir sands of the Aurora Pool and was selected for initial development with horizontal wells in the V-200 block. The Kuparuk C is characterized as lower to middle shore face sands deposited in a basal transgression (C-I) a middle progradational package (C-2 and C-3) and a capping transgressive package (C-4). The thickness of the C-sands is variable and ranges from 0 feet at the eastern truncation, to 210 feet at the Beechey Point wells in the northwestern portion of the Aurora Pool. The Kuparuk C-I and C-4 Megazones are coarser grained and contain variable amounts of glauconite and digenetic siderite. The volume and distribution of siderite and glauconite can significantly reduce reservoir quality of the Kuparuk C-I and C-4 intervals. These minerals are unevenly distributed and challenge open hole log interpretation of fluid contacts and pay. New Reservoir Description. Post Phase I Development, it became apparent that the maps, stratigraphic framework and resultant reservoir description required refinement. In conjunction with early appraisal and development drilling at the nearby sister field, Borealis, the decision was made to pull together a new integrated sub-regional Kuparuk River Fonnation geologic model and reservoir description. This new geologic model relied heavily on new cores taken at Aurora and Borealis as well data from the vast Kuparuk River Unit (KRU) dataset. The goal of this effort was to build an early reservoir description that is updateable and flexible enough to address a range of issues from well planning in undeveloped portions of the field to water flood implementation in more mature areas. Petrophysics, biostratigraphy, petrologic data, core analysis, ichnology and production data were integrated into a sequence stratigraphic framework to produce a robust geologic model. The. business challenge was.· t() . build a geologic description early in the fields' history while simultaneously planning and managing ongoing'. devel()PDlentlappraisal.. . drilling, < The resultant stratigraphic framework. and máps>bave had a significant impact in development planning at Aurora. See rIgure 4 for stratigraphic framework. Rock and Fluid Properties Field oil-water contacts have been interpreted to vary from 6812 feet tvdss to 6835 feet tvdss between the East and Northwest end of the field. Based on RFT data, core analysis saturations, and core staining, a gas-oil contact (GOC) is interpreted to vary from 663 I feet tvdss to 6678 feet tvdss between the East and Northwest end of the field. The reservoir description for the Aurora Pool is developed from the Aurora Log Model. Geolog's MuItimin is used as the porosityllitho logy solver and is based on density, neutron, and sonic porosity logs. Quality control procedures include normalization of the gamma ray, density and neutron logs. The Waxman-Smits correlation is used to model water saturations. Results from the log model are calibrated with core data, including litho logic descriptions, X-Ray diffraction and point count data, obtained from wells in the Aurora Pool and the nearby Borealis reservoir. Supplemental core data was analyzed from wells in the eastern portion of the Kuparuk River Unit (KRU). Wells with Aurora cored intervals in the data set are Beechey Point State # I, S-04, S-I04, and S-] 6. Porosity and Permeability. Porosity and penneability measurements were based upon routine core analysis (air penneability with Klinkenberg correction) from the following well set: S-]6, S-04, Beechey Point State #1, S-]04, NWE 1_ 01, NWE ]-02, and NWE 2-01. The ratio of vertical to horizontal penneability (kv/kb) was 0.006 per 20 feet interval, based on the hannonic average of routine core data. Typical single plug kv/kb ratios ranged from 0.4 to 1.2. ?-----" " SPE 76739 NEW DEVELOPMENT CASE HISTORY: AURORA 3 /" Hydrocarbons in Place Estimates of hydrocarbons in place for the Aurora Pool reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. The current estimate of original oil in place (OOIP) ranges between 110 mmstbo and 146 mmstbo primarily due to uncertainty in the GOC. Fonnation gas in place ranges from 75 to 100 bscf, and gas cap gas ranges from 15 to 75 bscf. Field Development Plan The... ..Aurora....accumulation had. been..recogniz~>.. a.~. a deyel()pment target as far back . as. thelateI960's,~ut .due to eX¡>e(:ted. ...·.Iow ipr~ucti.()~.<.ratesan<i >...i~ncertili~ty >...in .i..' ifluid contacts, .develoP01ent>\Vasnot<aggressively.pursued... As mentioned earlier, favorable results from the V-2oo exploration well generated sufficient enthusiasm to proceed with field development in 1999. An accelerated development plan utilizing existing Prudhoe Bay infrastructure with three separate phases was generated. Phase 1 Development Six wells were planned for the Phase 1 development drilling program with three wells located in the V-200 Fault Block and three wells in the North of Crest Fault Block. V-2OG Fault Block. The Aurora seismic survey indicated that the V-200 Fault Block was one of the least faulted in the field. In order to take advantage of the relatively large structure and thin reservoir, three horizontal wells were drilled for initial development. originally two producers, S-I 0 I and S-102, and one pre-produced injector, S-I 00. Gas-cap. A GOC was screened as possibility in the V-200 Fault Block but considered unlikely. S-101 was drilled into a GOC at approximately 6678' tvdss, con finned by an initial production test at over' 20,000 scf/stb. The high producing GOR plus the need to conserve reservoir energy led to S-101 being shut in shortly after initial production. Compartmentalization. '. Compartmentalization was recognized . prior to development, howeveritsi.extent. was underestimated and has had an impact on development plans. The first indication of this was encountering a significant change in the Kuparuk structure at the S-102 well that could not be detennined with seismic data. Top Kuparuk . was encountered 50'shallower than expectedintbis well,andåt least two faults were crossed, forcing the horizontal section to be shortened due . to missing fonnation. .IIIithll. pressure data andsubsequent.pr~ucti()n i. data.. sll~est thatS- JQ2is .in tortuous communication with the main V-200· block. See figure 5. Figure 5: 8-102 Compartmentalization -~--.... ja:.a.JFTöìiI-~ ! ~ÐD: fJi(;. (~~P!J~~~~ tot ~~~~~: æ50 .. 5 , ~ : c! i !:! 6100 ¡ ~ . ... '. '. 6l9J i--- I I I I i . V-2Dci~ , &24aI :IeSEUÐS V-2D (J QaáErt ... &102 AeIue 3310 ;œ¡ 3<10 .. - ------ ---------" 6fD); 3B) 30m 3fi} Pattern Reconfiguration. S-IOO, originally planned as the injector to support S-101 and S-102, was the best perfonning well in the fault block with initial rates in excess of 7000 bopd. There was considerable discomfort with converting the best producer in the block to injection service plus off take from S-1O 1 would be limited for several years due to gas influx. A proposal was made to re-configure the V -200 fault block to retain 8-100 as a producer and convert the 8-10 I well to injection. The ..... final. copfiguration\ had. to . meet three obj~ti~e~: ... .. .iwpr()ve rate,·· < inc~ease ·reserves,and meet economic hurdles; Injecti~.l1fT0tn;~-IOI. wo~l~provide ". excellent.. sweep to . the southofS- 100 but would not provide pressure support to the north. As the evaluation progressed on the V-200 fault block, the S-107i well was in the planning stages to provide injection support to the Northern Beechey fault block. The well trajectory passed over the mid-point between the S-I 02 and S- 100 wen locations. Anad4itional. injector was simulated in this loc~ti?natldjt pr?videdover· 1-2 MMSTBO of additional reserv7s·.I'".urther itallo\VedS-IQ() to. remain on production, substanti;illy increasing offtake from the V-200 fault block in 2001-2004. Once the location had been identified and benefits established, an economic way to access the target had to be found. A stand alone wen, a multilateral, and a high angle dual injection target wen were evaluated in tenns of cost, ease of drilling and operability. The best option was a V-shaped wen passing down through the Kuparuk in the V-2oo fault block then climbing back up to hit the Northern Beechey target from below. The dual target injection wen met an three objectives of a successful reconfiguration: keeping S-IOO on production, increasing reserves in the V-200 fault block, and was an SCANNED JUL 1 5 2004 4 \...../ \....../ J. P. YOUNG, F. E. BAKUN. F. K. PASKVAN, E H. WESTERGAARD - SPE 76739 economically viable project (development cost less than $I.OOlbbl for V-200 target). See Figures 6a and 6b for the S- 107i u-shaped wel1 along with base case and reconfigured patterns. The complete evaluation, approval, and implementation process for V-200 pattern reconfiguration took place in less than 4-months and did not delay the development schedule. Eady partner involvement and multi-disciplinary teamwork we're crucial to timeliness of this project. The North of Crest Fault Block. The North of Crest (NOC) area on the east side of Aurora was the next most favorable development target at Aurora. Because the NOC area is smaller and has a higher degree of structural complexity, it was developed with two vertical producers, S-103 andS-105, and one dual target injector, 8-104. Several well placement scenarios were simulated at various gas oil contacts. The final well locations were based on mitigating the risk of gas in the S-103 location. S-103, located at the highest point in the structure, was the first development wel1 in the block. Interpreted log data suggested a possible GOC in the C-4 sand at 6631' tvdss. To avoid high GOR production, initial perforations were limited to the C-I sand and had initial production of over 3000 bopd and proved excellent reservoir quality in the C-I in this fault block. Subsequent static pressures have suggested that there is a very active aquifer in the NOCarea. S-I04, drilled in central portion of the block, was a pre- produced injection well and initial unstimulated production was over 700 bopd. With slight modifications in the directional plan and completion equipment (tubing straddle), 8-104 was able to access injection targets in both the Kuparuk and shal10wer Schrader Bluff reservoirs for a fraction of the cost of2 sta.nd-alone wel1s. S-105, structurally the lowest of the three wells, was drilled very close to the low productivity NKUP 26-12-12 well and did not produce commercial rates initially due to a truncation of the higher quality C-4 sand. A fracture treatment in S-105 yielded sustained production of over 1000 bopd, and highlighted the fonnation damage concerns in the C-sand. Phase 2 Development The Phase 2 development program was initiated in 200 I to appraise and develop the remaining blocks in the Aurora field and reconfigure the V-2OO water flood pattern. The second phase of development drilling is expected to continue through 2003-4. Beechey. The Beechey Fault Block, on the western edge of the Aurora field, had very high potential reserves but an uncertain gas oil contact. Mud logs from the Beechey State #1 exploration wel1 had a broad range of interpreted GOC's ranging from 6648' tvdss down to 6705' tvdss. It was recognized that if the GOC was shallow, then up to 7 wel1s could be drilled in this portion of the field. A phased drilling approach was chosen for this block to help mitigate development risk. S-106 was dril1ed first, in mid 200 I, to define the gas oil contact and prove up productivity. Post hydraulic fracturing, the well tested at over 6000 bopd confinning the presence of high quality Kuparuk C-Sands. While the well did not intersect the GOC, production results suggest a GOC at approximately 6678' tvdss, consistent with the V-200 Fault Block. As mentioned earlier, the S-I 07i well was dril1ed as a u-shaped injector to provide injection support to the S-106 wel1 and reconfigure the V-200 fault block. Based on the results of the S-106 producer, two additional wells are being evaluated for the Mid-Beechey Fault Block target (producer/injector pair) and three wells for the South Beechey Fault Block target. AdditionaL simulation and further production testing are required before the development wíll continue in this block. Southeast Crest. The Southeast Crest (SEC) Fault Block was the next development target. The Kuparuk C-sands thin significantly moving towards the southeast and a key uncertainty was well deliverability. Limited core data from the S-16 well suggested that a hydraulically fractured well could produce at economic rates. Two wells were drilled in 2001 in the northern portion of the block, S-108 and S-I1O. Both wells had post hydraulic fracture rates in excess of 1500 bopd. Based on the deliverability of the first two wells an injector and an additional producer are being evaluated. The two additional wells are expected to encounter thinner, but generally higher penneability rock in the central and southwest portions of the block. Crest. The Crest. Fault Block carries significant structural uncertainty and has not been drilled as part of the Aurora development. The block has been penetrated several times with Prudhoe Bay Ivishak wells and open hole logs have demonstrated that Kuparuk sands are present. Unfortunately, the dense faulting raises serious concerns about·· the connectivity of each small compartment. It is expected that one well will eventually be drilled to test this area and if multiple blocks are communicating then up to 3 more wells could be drilled. Phase 3 Enhanced Oil Recovery The final Phase of development wíll occur concurrently with Phase 2 Development in which miscible gas will be utilized at Aurora to improve ultimate recovery. Early screening indicates EOR benefits on the order of 5% incremental oil recovery. The 8-104 single well tracer test was utilized to prove in-situ miscibility. See the Single Well Tracer Test section. ~ 5PE 76739 /~. NEW DEVELOPMENT CASE HISTORY: AURORA 5 Facilities design Aurora wells were drilled from an existing IP A drill site, S- Pad, and utilized existing IPA pad facilities and pipelines to produce Aurora reservoir fluids for processing and shipment to the Transalaska Pipeline System (TAPS). Aurora fluids are commingled with IPA fluids on the surface at S-Pad to maximize use of existing IPA infrastructure, minimize environmental impacts and to reduce costs to help maximize recovery. Use of existing facilities, reduced capital expenditure and allowed the project to be accelerated by providing early access to test separation equipment, injection water, and miscible injectant for EOR. The disadvantages were added drilling cost to reach reservoir targets, and close proximity of surface well locations, which caused delays due to equipment and simultaneous operations limitations. Well Design and Completions The horizontal well completions were designed to reach targets from existing infrastructure while maximizing horizontal displacement in the reservoir for increased productivity. Because formation damage was a concern, "banzai" completions, a combination of slotted and cemented/perforated liner, were used to minimize damage while allowing for fracture stimulation if necessary. The initial wells were completed with 7" production casing in vertical wells, 4-1/2" liners in horizontal wells. All the wells were perforated at 6spf with 60 degree, deep penetrating charges, and 0-1500 psi under-balance, depending on operational limitations. Field Development Learnings Because. of the pay quality and fluid cont¡ct ris~ at. Aurora, evolvementof the development planwasçriticaL In addition to the stratigraphic framework mentioned earlier, we feel the following learnings had a favorable impact on, and were key to sustaining Aurora field development. Single well tracer test. As a small satellite Aurora does not have the scale to warrant a significant investment for the collection of native state core and special core analysis. Therefore properties like relatively permeability were based on analog data. The single well tracer test (SWIT) provided an economic way to collect the following key reservoir parameters in-situ: initial water saturation, water-oil rel~tive permeability, residual oil saturation to water flood and resIdual oil saturation to miscible gas. S-I04 was drilled in I Q 200 I and was selected to be the key data well for the Aurora field. The well was cored and standard core analysis was performed, plus a full suite of open hole logs was run including nuclear magnetic resonance. and focused microresistivity. The well was consIdered an Ideal candidate for a single well tracer test as it had a quality cement job and a detailed near well bore description. The SWIT was performed over a 30' interval in the S-I 04 well. The connate water saturation test returned a value of 13.5%, considerably lower than the predicted 25-30%. This suggests a higher OOJP in reservoir. The residual oil saturation to water flood plus the water-oil relative permeability data suggested that the system was more oil-wet than analog data had suggested. The residual oil saturation to miscible gas was very low even with a minimal pressure delta at the perforations. The miscible gas entered the upper 80% of the open zone and swept it down to a residual oil saturation of 4.5%. Ififorrn~tionfJ'()mthç$~J1'¡It1P~t~"'.iQjeçt()r. spacing,. rate andr~ç.()vçryestimatesandhighlightedthe need to accelerate EORstartUp. Productivity Data. Following promising results of the V -200 exploration well, the initial development began at Aurora with three horizontal wells followed by three conventional wells. Substantial log, core, and production data, including pressure transient analysis (PT A) was collected and is summarized in table 2. Table 2 Aurora Phase I Well Results 5-100 5-101 Horiz. S-102 Hortz. Conv. S-103 (C-1) 5-104 Cored 5-105 Conv. 769 8-105 Frac'd 769 Pressure buildup and production log analysis showed significant skins in perforated completions, even when steps were taken to minimize formation damage with the use of KCL drilling fluid and under balanced perforatingl. The inability to achieve extreme under balance conditions required for perforation cleanup resulted in the lower permeability layers not communicating with the well bore. See figur~ 7 for a comparison of perforation skin and under balance Iß the Aurora wells relative to published under balance requirements for 0 perforation skin in Berea sandstone2. After fracturing S-105 and performing PT A, it was apparent that the permeability-thickness (kh) increased dramatically, even without correcting for relatiy.e. ,permeability.' -Increased . kh resulting from fracturing into lower permeability layers has been documented at the Kuparuk River Unit3. " SCANNED .JUt 1 5 7004 ''-/' 6 '~ J, P. YOUNG, F. E BAKUN, F. K PASKVAN. E. H. WESTERGAARD SPE 76739 The low kv/Kh also hindered productivity from horizontal wells relative to fractured wells. Shawn in figure 8 is a plot of productivity index, no.nnalized to kh for Phase I and 2 Aurora wells versus net horizontal length or fracture length. Even when great care was taken to maximize productivity with long, open-hole completion horizontal wells, the stimulation benefit did not compete with a high conductivity propped fracture. By providing excellent vertical communication to the full reservo.ir, high conductivity, tip screen out (TSO) fractures provided superior productivity at a much lower cost than horizontal wells. Conclusions The fallowing advancements were key to. development at the Aurora field: I) Success of the V -200 exploratio.n well in attracting investment by achieving a commercial rate well test. 2) Use of existing facilities to minimize construction impacts and costs. 3) Reprocessed seismic data continually updated with well control to. refine structural descriptio.n, compartmentalizatio.n issues, and well placement. 4) Stratigraphic framewo.rkusinglo.g, core, and analogue data to. map reservo.ir quality variations and refine reservoir descriptio.n. 5) Fit-for-purpose well trajectory and co.mpletion designs to match reservoir description (ho.rizontaVdual target wells and TSO fracturing). 6) A single well tracer test provided key in-situ reservoir parameters in a timely manner that allowed for impact on development plans. 7) Investment.in reservoir descriptio.nled to. significant changes in the development plan. 8) Proactive surveillance leads to. accurate decisio.n-making, inno.vation and o.pportunity. Acknowledgements The authors would like to thank the management of BP, Exxo.n Mo.bil and Phillips far pennission to. publish this paper. We would also like to. acknowledge the contributions of staff in Exxon Mo.bil, Phillips and BP who have wo.rked on develo.ping Aurora over the last 3 years. Specific thanks to Frank Paskvan for reservoir modelling and initial develo.pment planning, Gary Molinero for geophysical interpretatio.n of the structure, Ray Eastwood for developing the Aurora log model, and Bruce Weiler for facility planning. References I. Bloys, J.B., Murphy, J., Weingarten, J.S., Wheatall, "Drilling and Completing Wells for High Productivity in the Point Mcintyre field; Strategy, Implementation and Verification", SPE 3046 I presented at the Annual Technical Co.nference, Dallas, TX, Oct., 1995. 2. Behnnann, L.A., "Underbalance Criterita fo.r Minimum Fonnation Damage", SPE 30081 presented at the SPE European Fonnation Damage Conference, Hague, Netherlands, May, 1995. 3. Pospisill, G., Lynch, K.W., Pearson, C.W., and Rugen, l.A.: "Results of a Large-Scale Refracture Stimulation Program, Kuparuk River Unit, Alaska," SPE 24857 presented at the Annual Technical Conference, Washington, D.C., Oct., 1992. Nomenclature Bopd = stock tank barrels of oil per day EOR = enhanced oil recovery GOR = Gas oil ratio Kv/Kh = ratio of vertical to hori::ontal permeability koil = Permeability to oil md-ft = millidarcy-feet OOlP = Original Oil in Place RFT = Repeatformation tester 81 Metric Conversion Factors Bbl x 1.587873 E-O) m3 Ft x 3.048 E-OI=m Psi x 6.894757 E+OO=KPa ,~ /""". . SPE 76739 NEW DEVELOPMENT CASE HISTORY: AURORA 7 Appendix Figure 1: Location Map Ji!!I. Kup¡aruk o NonKuparuk Figure 2: Top Structure I I I : ¡ ____._.-L.._~ '..1 , >. .' Reservoir Properties Deposition Shore face GOC 6631 - 6678 tvdss OWC 6812 - 6835 tvdss OOIP 110 -140 MMBO GOIP 50 - 75 BSCF Permeability 10 - 150 md Kv/Kh .001 - 1.0+ Porosity 16 - 25 % # Wells17-25 SCANNED JUL 1 5 2004 8 '~ ,--,,' J. P. YOUNG, F. E BAKUN, F. K. PASKVAN. E. H. WESTERGAARD SPE 76739 - Figure 3: Type log .. 5 II II WI) ~ ~ ~ 0 II IDtZ C4 b 6J!1~¡' C3 ~.) C2 d c b y C1 .. ?I.:w B 2001 AURORA-BOREALIS RESERVOIR DESCRIPTION AURORA TYPE LOG V-200 NPH~ .CN\.. _ 1 ~ f~HOB, t:.~r.::r:,:;: ÞE:RM,.9 VCLkV _GR_' ~ F-t,q MO '?(UJ w.. \Yo::.t"'9ô'4"dtf>'01 Figure 4: Stratigraphic Framework h: !.~;¡?c:;,.~ !1_;'& "1 :¡!<./~: ;·h/('!'-.";:;' ::> C5? z Vi .. ~'" ; ::;~ >-.... C-4 '" <~ U zOo. U g~ .. C4 ., :io.: 0.. C-3 C3d ':E C3, ;:; z ;: C3b .. z ~ <t. 0 '" I w . .. :> ~ C-2 a Z « Cly " "" >'> D -'~ § C-l Cly ~ft t,;.;~ -' ::> 1 '" , -'<f.!J.,4 to",> ¡.6;.; 1~' ~ :::'~f_"IV: ~,- ~ ~ _~ A :: :..~~ I Estuary ? "ransit¡onOl Shelf Lowcr Shoreface M¡dd~ Shor" fac" · P2Bc.1ßi 5S fGCi~S, r..~d'ur.1 1.0 c.~arsf!. gr::d". w¡~h e);tc.r;s,·"t: s:~ œmer,T , Comp1lCc,ied ¡n1erva wi se.erc:; :stc{;~'J;d rn::;r$gl"'e$s!ve -:í;,,;rf~c.es · Gram S~le more coa~se abc....~ BroiJfr, d,s('cr'\ti~;j~ty · Overall fi!".¡r'9 upwo~d · G¡ou-cor¡iTe; or.d 5Jcer(Te cOI'!'.m~r: Middl.o: Shorefoce · O·,e:rall progracatlc1'! cf ,~'~r~r.ir,g u~wo!"'d ''fdes · Eoch c.yc(£ f'yt'õC.oily boul'1ded by flooding e....tn-s Proximal Lowcr Shorefacc · Fa,íes irtep.foTlg¡,,;;e Ir. ¢verc1l clecr.;r:g upwcr-d 1ter..d .. EJ(1er,i"ive b¡otu~bc:ticr, has mixed st:d¡r."\z:~t to e:>;!er.t th~· the-roe contir,uU!'n of ~)'cr rock p~opt.rt;£s Distal Low"r hordoce \ T~"''''o~1 Sholf · Slo,<, ro.1es of depcsi1iQrI · Loy~f's dcwr, lap or-to Gt'ee.n N.f 5 · Layers prog,ess:yerr tr'.;r:(:c1~d by ts1'"owr f,.of":\. f'çrth 'ro sõ¡.¡th · PrC9rcdu':g f..JNW ran5,tlonol Shelf · Cho1"cC,er>le.d by stoc.¡"ed f.r¡r,g ~Þ~·::~d cy-:;e~ v>':';"", e~o<:;:6r'tt$b$ - Groir. s¡ze. rcr.ges froM VCS 10 :sdr · ?!;Ter!Tlol thief zont, · Or-!cps pre--ex~S!1!''''9 LCV t¢P(¡9"~phy ower Shoreface ----.....--... SPE 76739 ----- ,~. NEW DEVELOPMENT CASE HISTORY: AURORA 9 Figures 6a and 6b: Pattern Reconfiguration and $-107 Well !U2 néi ;itl ~l~i 5JU ;;./J ~22, ;uz (\ j ril \1:1 ('\[,..,...('\~ orIn '"I-I Vi: i''t¡-~: X"'¡...;¡ ¡¡lli ,j . v , _. 1., \,I.... _. . v v I..r __ \.I V '-' u i ~ ----' ~ Sf '.. . f; 4NH ~ c SCANNED JUL 1 5 2004 '--./ \-.-1 10 J.P.YOUNG,F.E.BAKUN,F.K.PASKVAN,E.H.WESTERGAARD SPE 76739 Figure 7: Perforation Skin Aurora Perforating results 100 10,000 ~ i IL 10 c: ;¡¡ '" ~~- ~~ ~. ~- ~__ ~·4' ><"tw_ ...... ~ ..... ~ ~- extreme US required for lower perm . . . . + Skin calc. from Test . . . Underbalance, psi . . . .. CL Õ .. c: I 1.000 i ... c: ::) -SPE30081 US for Oskin, BereaSS . -~-J >0, . . 10 100 1,000 Fm. permeability. md Aurora Hz V5. Frae Well results 3.0 I . I . 2.51 0.5 +Open hole/Cmtd Hz Wells . Fracs,$-105(no TSO),6.8,10 ---~-_. î 2.0 t .8 . i 1.5 -----+---,----. ( § . ~ 1.0 ~ i I . , L ¡ 5-100 perl'd, damaged? ! ....____·1___·-. ~ . . i 1 -~ --·-----r--· I I I I 0.0 o 200 400 600 800 1000 1200 1400 1600 Effective Horiz. Length In Pay -or- Free 1/2 Length (ft) ~ ".-..... Attachment 4 AURORA REPRESENTATIVE WELL PRESSURES SCANNED JUL 1 5 7004