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CO 457
Conservation Order Cover Page XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. ,L./~ ~;/--_ Conservation Order Category Identifier Organizing idon~! RESCAN ~--. DIGITAL DATA OVERSIZED (Scannable with large plotter/scanner) ~'"'"~Color items: [] Diskettes, No. [] Maps: [] Grayscale items: [] Other, No/Type [] Other items [] Poor Quality Originals: OVERSIZED (Not suitable for [] Other: plotter/scanner, may work with ~'"'~ Logs of various kinds [] Other NOTES: BY: .... ~'~"'MARIA ~ ,,, ~,? Scanning Preparation BY: ~ MARIA Production Scanning Stage 1 PAGE COUNT FROM SCANNED DOCUMENT: ~,..?_'~ ,~ PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: YES NO Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: ~ YES ~ NO (SCANNING IS COMPLETE AT THIS POINT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA ) EXPLORATION (ALASKA) INC. ) for an order to establish pool rules for) development of the Aurora Oil Pool, ) Prudhoe Bay Field, North Slope, ) Alaska ) ) Conservation Order No. 457 Prudhoe Bay Field Aurora Oil Pool (formerly Kupamk River Oil Pool) September 7, 2001 IT APPEARING THAT: , . . o By letter and application dated June 15, 2001, BPXA Exploration (Alaska) Inc. ("BPXA") requested an order from the Alaska Oil and Gas Conservation Commission ("Commission") to define a proposed Aurora Oil Pool encompassing the Aurora Participating Area ("APA") of the Prudhoe Bay Unit and to prescribe rules governing the development and operation of the pool. Notice of opportunity for public hearing was published in the Anchorage Daily News on June 22, 2001. The Commission did not receive a protest. 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 July 24, 2001. Concurrently, the Commission heard testimony concerning proposed injection of fluids for enhanced recovery from the proposed pool. BPXA submitted a revised application "Aurora Pool Rules and Area Injection Application-July 23, 2001". This application included supplemental information requested by the Commission. Additional information and data were requested by the Commission at the hearing and have been provided to the Commission. This supplemental information was submitted by letter from BPXA dated July 31,2001. Conservation Order No. 457 September 7, 2001 Page 2 FINDINGS: 1. The proposed Aurora Oil Pool ("AOP") encompasses portions of Township 12N- R12E, and Tl lN-R12E, Umiat Meridian, on which are located Alaska State Leases ADL-28255, ADL-28256, ADL-28257, ADL-28258, ADL-28259, and ADL 28261. The known extent of the proposed pool is located within the current boundaries of the Prudhoe Bay Unit ("PBU"), North Slope, Alaska. 2. The Department of Natural Resources, Division of Oil and Gas ("Division"), approved an expansion of the Prudhoe Bay Unit ("PBU") and formation of an initial Aurora Participating Area on December 20, 2000. The Aurora Participating Area was delineated by drilling within the Kuparuk River Formation in the vicinity of S Pad. The Division's decision provided that the participating area will be automatically expanded when and if BPXA drills "Qualified Wells" within defined expansion areas. Attachment 1 shows an outline of the participating area and the expansion areas. In this order, the term "APA" means the Aurora Participating Area including the expansion areas when and if the initial Aurora Participating Area is expanded to include them. 3. The area proposed to be covered by the requested AOP pool rules corresponds to the APA and expansion areas. 4. BPXA is the operator of the APA. BPXA, Phillips Petroleum, Co., ExxonMobil Corporation, and Forest Oil are working interest owners ("WIOs") in the APA. The State of Alaska is the landowner. 5. The reservoir interval of the proposed AOP is the Kuparuk River Formation. The proposed pool is an accumulation of hydrocarbons that is common to, and correlates with, the interval between 6859' and 7254' measured depth in Prudhoe Bay Unit well V-200. 6. Conservation Order No. 98-A (CO 98-A) defined the Kuparuk River Oil Pool within the Prudhoe Bay Field ("PBKROP") and prescribed rules governing the development and operation of the pool. The PBKROP was defined as the accumulation of oil that is common to and correlates with the accumulation found in the Mobil Oil Corporation Mobil-Phillips North Kupamk State No. 26-12-12 well between the depths of 6,765 and 7,765 feet. This is the same accumulation that the applicant proposes to be defined as the Aurora Oil Pool. The Mobil Oil Corporation Mobil-Phillips North Kupamk State No. 26-12-12 well is located within the APA, as is Prudhoe Bay Unit well V-200. 7. Conservation Order No. 349A amended CO 98-A by reducing the extent of the area to which the rules prescribed in CO 98-A applies. 8. The area proposed to be covered by the requested pool rules is encompassed within the area to which the rules prescribed in CO 98-A, as amended by Conservation Order No. 349A, apply. Conservation Order No. 457 September 7, 2001 Page 3 . 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 21. 22. Data submitted by BPXA cast doubt on whether the PBKROP extends into the entire area to which the rules prescribed in CO 98-A, as amended by Conservation Order 349A, apply. Only limited drilling activities, preliminary to pool development, are occurring outside the APA in the area to which the rules prescribed in CO 98-A, as amended by Conservation Order No. 349A, apply. The Kuparuk River Formation in the AOP was deposited as Early Cretaceous marine shoreface and offshore sediments, and is composed of very fine to medium grained quartz rich sandstone, interbedded with siltstone and mudstone. The Kuparuk River Formation in the AOP is stratigraphically complex, characterized by multiple uncomformities, changes in thickness and sedimentary facies, and local diagenetic cementation. The AOP Kupamk River Formation reservoir is divided into three stratigraphic intervals, from the base to the top of the formation, the A, B and C. The A Zone, the stratigraphically lowest zone, contains two reservoir quality sub- intervals; the A-4 and A-5 sands, which are typically 30 and 20 feet thick respectively. The B zone is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are three feet thick. The uppermost unit, the Kuparuk C interval, contains the primary reservoir sands of the AOP. The C interval is characterized by thick amalgamated sands, with high net to gross ratios. The Kuparuk River Formation in the AOP is highly faulted with displacements ranging to hundreds of feet. Fluid contacts (oil/water and gas/oil) appear to be variable across the AOP. The stratigraphic character of the Kuparuk River Formation and style of structural deformation typical in the AOP is similar to that documented in the adjacent Kuparuk River Unit and the Milne Point Unit. Fault related compartmentalization of the AOP may be reasonably anticipated. The distribution and frequency of pressure measurements required for reservoir management of the AOP will be dependent on the degree of pressure compartmentalization determined by development drilling. Porosity and permeability measurements were based upon routine core analysis of Kuparuk Formation wells in the area. Average layer properties range between 16% for the A sand net pay interval, and 25% for C sand net pay intervals. The average permeabilities for these layers range from 12 md to 158 md. Conservation Order No. 457 September 7, 2001 Page 4 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. Five exploratory wells in the area have been tested in the Kuparuk Formation. The V-200 appraisal well drilled from an ice pad in 1999, tested at a rate of 1915 bopd with a GOR of 718 scf/stb, with 29.6 API gravity oil. The V-200 has been plugged and abandoned. With successful test of the V-200 well, the WIOs proceeded with evaluation and development of the Kuparuk Formation from Well Pad S in the PBU. Phase 1 drilling in year 2000 included three wells drilled from S Pad, S-100, S-101, and S- I 02. Phase II development will include six to eight producers and three to four injectors. Six wells have been drilled or planned for 2001. BPXA presented results of three of these wells, S-103, S-104 and S-105. Based upon current well control and seismic information, BPXA estimates 110 to 146 MMSTB original oil in place. Model studies conducted suggest primary oil recovery of approximately 12% and waterflood recovery of 34%. Waterflood is part of BPXA current development plans. Production rate peak for the proposed development plan is estimated at 14,000- 17,000 bopd with a maximum water injection rate of 20,000-30,000 bwpd. BPXA is concurrently requesting conversion of S-101 to water injection for support of current producers (S-100 and S-102). BPXA plans to fully replace and balance voidage with waterflood. Initially, an injection to production ratio greater than 1:1 may be required to restore reservoir pressure. BPXA requested 80 acres minimum spacing. The Commission asked BPXA if 40 acre minimum spacing would cause any problems, to which they stated, no. As long as adequate pressure maintenance is effected, 40 acre well spacing will not adversely affect ultimate recovery. Reservoir PVT studies were conducted from recombined surface test separator samples and RFT downhole samples obtained from V-200. The API gravity was 29.1° AP1, with a solution gas oil ratio of 717 scf/stb. Formation volume factor of 1.345 RVB/STB and oil viscosity of 0.722 cp at reservoir pressure and temperature. The APl oil gravity measured from wells in the AOP, range from 25.2° to 29.1° API. One well, S-101, had an initial AP1 gravity of 47°API, however, the elevated API was due to the production of gas condensate liquids. Initial reservoir pressure based upon RFT data from V-200 is 3433 psi at 6700' tvdss. Reservoir temperature is approximately 150 degrees Fahrenheit at 6700' tvdss. Conservation Order No. 457 September 7, 2001 Page 5 34. 35. 36. 37. 38. 39. 40. 41. 42. The development of the APA is planned entirely from the PBU drill site, S-Pad and will utilize existing Prudhoe Bay Unit facilities and pipelines for production and water injection. Production will be processed at Gathering Center 2 (GC2). A 24" low-pressure pipeline, a 10" gas lift supply line, and a 14" water injection supply line are also in place. Additional facilities expansions are as follows: a. A gravel expansion of S Pad to accommodate additional wells at S-pad, completed in April, 2000. b. A new production manifold system to accommodate up 20 Aurora wells. c. An extension of an existing 6" water injection supply line. Estimated water injection available for proposed AOP is 28,000 BPXA at a pressure of 2000-2100 psig. Local water injection booster pumps may be added if injection pressures and rates are insufficient to support the waterflood. Gas lift will be utilized for artificial lift in the AOP wells. Estimated gas lift supply available for production wells is 30 MMscfd at 1800 psig. Wells will be drilled according to AOGCC regulations. Horizontal and vertical wells are anticipated. Fracture stimulation may be necessary. A 20" conductor will be set at 80' below pad level, and surface hole will be drilled to 2300 ft tvdss, minimum. Production hole will be drilled below surface casing to the Kuparuk Formation. Liners may be used in certain instances. BPXA plans to install Surface Safety Valves Systems on all wells per AOGCC regulations. BPXA requested that sub-surface safety valves not be included. This requirement was a stipulation of CO 98-A. All wells will be equipped with SSSV nipples, should the need arise to install subsurface storm chokes or pressure operated safety valves. BPXA intends to install such flow control devices in wells utilized for gas or miscible gas injection. The development plan proposed by BPXA for the AOP is based on analysis of large volumes of recent geologic and engineering data and differs materially from development scenarios anticipated when CO 98-A was issued. BPXA provided a letter summarizing the draft PBU Satellite Production Metering Plan dated July 23, 2001. BPXA proposes this plan be adopted for the AOP. The Commission has not received a final copy of this plan. CONCLUSIONS: o The existing PBKROP pool rules established in CO 98-A are no longer suitable in their entirety for pool development and operation in the APA. Conservation Order No. 457 September 7, 2001 Page 6 . o , o o The existing PBKROP pool rules established in CO 98-A add little to the statewide requirements of the current Commission regulations, 20 AAC 25. Given the limited extent of the activities that are occurring in portions of the area covered by CO 98-A, as amended by Conservation Order No. 349A, outside the APA, and given that the data that have become available since CO 98-A was issued suggest that those portions may be largely outside the PBKROP, it is not essential to maintain the pool rules in effect for those portions. 40 acre spacing should be adopted for the AOP. This spacing will not cause waste, compromise ultimate recovery, or jeopardize correlative rights. No reason appears why the setback requirements established in statewide well spacing rules, 20 AAC 25.055(a)(1)and (2), should not apply to the exterior boundary of the APA. Monitoring of reservoir performance by measurement of production and reservoir pressure using standard industry practices on a regular basis will help ensure proper management of the pool. Surface commingling of AOP fluids produced from the APA with produced fluids from other pools and tract operations within the PBU is appropriate provided there are adequate well tests to assure accurate production allocation. NOW THEREFORE IT IS ORDERED: 1. CO 98-A is amended, and to the extent inconsistent with the provisions of this order is superseded, by this order. 2. The name of the pool defined in CO 98-A is changed to the Aurora Oil Pool. 3. The rules set out below replace Rules 2 through 8 as established in CO 98-A and apply (in addition to the statewide requirements under 20 AAC 25 to the extent not superseded by these rules) to the following described area: Umiat Meridian Township Range Sections T11N R12E N ½ Sec. 3 T12N R12E S ½ Sec 17; SE ¼ Sec 18; E ½ Sec 19; All Sec 20; All Sec 21;W 1/2NW 1/4,S ½ Sec 22; SW ¼ Sec 23; SW ¼ Sec 25; All Sec 26; All Sec 27; All Sec 28; N ½, Se ¼ Sec 29; E ½ Sec 32; All Sec 33; All Sec 34; All Sec 35; N ½, SW ¼ Sec 36 Rule 1 Well Spacing Spacing units within the pool shall be a minimum of 40 acres. 20 AAC 25.055(a)(1) and (2) shall not apply to property lines within the external boundaries of the APA. Conservation Order No. 457 September 7, 2001 Page 7 Rule 2 Casing and Cementing Practices a) In addition to the requirements of 20 AAC 25.030, the conductor casing must be set at least 75 feet below the surface. b) In addition to the requirements of 20 AAC 25.030, the surface casing must be set at least 500' tvdss below the permafrost. Rule 3 Automatic Shut-in Equipment a. All wells must be equipped with a fail-safe automatic surface safety valve system capable of detecting and preventing an uncontrolled flow. b. The wells must be equipped with a landing nipple at a depth below permafrost, which is suitable for the future installation of a downhole flow control device to control subsurface flow. The Commission may require such installation by administrative action. c. Safety Valve Systems must be maintained in good working order at all times and must be tested at maximum six-month intervals or other schedule prescribed by the Commission. Rule 4 Common Production Facilities and Surface Commingling a) The operator shall submit to the Commission for approval the finalized PBU Western Satellite Metering Plan or other plan for allocation of production from the Aurora Oil Pool. b) The PBU Western Satellite Metering Plan must satisfy the well testing requirements of 20 AAC 25.230 and 20 AAC 25.275. b) Each producing well must be tested a minimum of twice per month. c) Until the Prudhoe Bay Unit Western Satellite Metering Plan or other allocation plan is approved and implemented, the Aurora Oil Pool allocation factor shall be 1.0. d) The Commission may require more frequent or longer tests if the allocation quality deteriorates. e) The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. f) The operator shall provide the Commission with a well test and allocation review report in conjunction with an annual reservoir surveillance report. Rule 5 Reservoir Pressure Monitoring a) Prior to regular production or injection, an initial pressure survey must be taken in each well. Conservation Order No. 457 September 7, 2001 Page 8 b) The minimum number of bottom-hole pressure surveys acquired each year shall equal the number of governmental sections within the Aurora Oil Pool that contain active wells. A minimum of four surveys will be required each year in representative areas of the Aurora Oil Pool. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement. c) The reservoir pressure datum will be 6,700 feet TVDss. d) Pressure surveys may be stabilized static pressure measurements at bottom-hole or extrapolated from surface (single phase fluid conditions), pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. e) Data and results from all relevant reservoir pressure surveys must be reported quarterly on Form 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Form 10-412, but must be available to the Commission upon request. f) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with paragraph (e) of this rule. Rule 6 Gas-Oil Ratio Exemption Wells producing from the Aurora Oil Pool are exempt from the gas-oil-ratio limits of 20 AAC 25.240(a) so long as requirements of 20 AAC25.240(b) are met. Rule 7 Enhanced Oil Recovery or Reservoir Pressure Maintenance Operations Enhanced oil recovery or reservoir pressure maintenance operations must be initiated within six months after this order is issued. Rule 8 Reservoir Surveillance Report An annual reservoir surveillance report for the prior calendar year will be required after one year of regular production and annually thereafter. The report shall include, but is not limited to, the following: a) Progress of enhanced recovery project implementation and reservoir management summary including results of reservoir simulation techniques. b) Voidage balance by month of produced fluids and injected fluids and cumulative status for each producing interval. c) Summary and analysis of reservoir pressure surveys within the pool. d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys, observation well surveys, and any other special monitoring. e) Review of pool production allocation factors and issues over the prior year. f) Future development plans. Conservation Order No. 457 September 7, 2001 g) Review of Annual Plan of Operations and Development. Page 9 Rule 9 Production Anomalies In the event of oil production capacity proration at or from the Prudhoe Bay Unit facilities, all commingled reservoirs produced through the Prudhoe Bay Unit facilities will be prorated by an equivalent percentage of oil production, unless this will result in surface or subsurface equipment damage. Rule 10 Administrative Action Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, and is based on sound engineering and geoscience principles. DONE at Anchorage, Alaska and dated September 7, 2001. Cammy Oe~)sli Taylor, Cl()ir Commission , ..~~ j~seC;I~ti~loiS~,k~ '.7/~~~s~ i iSic°onemrmission Julie M. Heusser, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., l0th day after the application for rehearing was filed). ATTACHMENT 1 EXHIBIT I-3 Amended (BP Supplemental Information received 7/31/01) AURORA PARTICIPATING AREA (APA) ADLi28254 ~9 2O Expansion 16 ADLi28253 ~ Exp' ~ Area 4 Area 3 30 ~ 29 ! ADU 28259 ~ ":,;£,,,,,,,, ~, ,, . i,r, i Area 2 I 28258 15 ADL 385193 ADL AD[ ADL 28 PBU Bo~ ADL 47448 ~ndary 25 T12N-R12E 22 ADLi 47450 27 APA 23 34 26 28258 :ir '"'ll,llll~ll!~II i~!, ~:1,,111 i,'!,:, i¢:l'~':lg:lll:¢l"ll~ll'll:llUllla ':? ::llli,:,,lL,:?~l'g:"Im~, fl, Exp,ansi, ....... Area 1 35 4 3 2 ADL ADL 28261 36 T11N-R12E 28280 PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION P O BOX 2221 NEW YORK, NY 10163-2221 OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 DPC, DANIEL DONKEL 2121 NORTH BAYSHORE DR #616 MIAMI, FL 33137 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 AMOCO CORP 2002A, LIBRARY/INFO CTR P O BOX 87703 CHICAGO, IL 60680-0703 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 IOGCC, P O BOX 53127 OKLAHOMA CITY, OK 73152-3127 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 OIL & GAS JOURNAL, LAURA BELL P O BOX 1260 TULSA, OK 74101 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 BAPI RAJU 335 PINYON LN COPPELL, TX 75019 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 DEGOLYER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 STANDARD AMERICAN OIL CO, AL GRIFFITH P O BOX 370 GRANBURY, TX 76048 XTO ENERGY, MARYJONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 SHELL WESTERN E&P INC, G.S. NADY P O BOX 576 HOUSTON, TX 77001-0574 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 6OO TRAVIS ST HOUSTON, TX 77002-2979 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 P O BOX 4813 HOUSTON, TX 77210 UNOCAL, REVENUE ACCOUNTING P O BOX 4531 HOUSTON, TX 77210-4531 EXXON EXPLORATION CO., T E ALFORD P O BOX 4778 HOUSTON, TX 77210-4778 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 P O BOX 4778 HOUSTON, TX 77210-4778 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLINGTON P O BOX 1635 HOUSTON, TX 77251 PETR INFO, DAVID PHILLIPS P O BOX 1702 HOUSTON, TX 77251-1702 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 WORLD OIL, DONNA WILLIAMS P O BOX 26O8 HOUSTON, TX 77252 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 P O BOX 2180 HOUSTON, TX 77252-2180 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 P O BOX 2180 HOUSTON, TX 77252-2180 PENNZOIL E&P, WILL D MCCROCKLIN P O BOX 2967 HOUSTON, TX 77252-2967 CHEVRON CHEM CO, LIBRARY & INFO CTR P O BOX 2100 HOUSTON, TX 77252-9987 MARATHON, Ms. Norma L. Calvert P O BOX 3128, Ste 3915 HOUSTON, TX 77253-3128 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TEXACO INC, R Ewing Clemons P O BOX 430 BELLAIRE, TX 77402-0430 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 INTL OIL SCOUTS, MASON MAP SERV INC P O BOX 338 AUSTIN, TX 78767 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 GEORGE G VAUGHT JR P O BOX 13557 DENVER, CO 80201 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 C & R INDUSTRIES, INC.,, KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING P O BOX 1655 COLORADO SPRINGS, CO 1655 80901- RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 MUNGER OIL INFOR SERV INC, P O BOX 45738 LOS ANGELES, CA 90045-0738 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 BABSON & SHEPPARD, JOHN F BERGQUIST P O BOX 8279 VIKING STN LONG BEACH, CA 90808-0279 ANTONIO MADRID P O BOX 94625 PASADENA, CA 91109 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 TEXACO INC, Portfolio Team Manager R W HILL P O BOX 5197x Bakersfield, CA 93388 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 ECONOMIC INSIGHT INC, SAM VAN VACTOR P O BOX 683 PORTLAND, OR 97207 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 715 1 ST #4 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 995O1 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 GAFO, GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DNR, DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 ARLEN EHM GEOL CONSLTNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 UOA/ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 US BLM AK DIST OFC, GEOLOGIST ARTHUR BANET 949 EAST 36TH AVE STE 308 ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 , GORDON J. SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, LIBRARY 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 CIRI, LAND DEPT P O BOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 ANCHORAGE TIMES, BERT TARRANT P O BOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, JOANN GRUBER ATO 712 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER P O BOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 P O BOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON P O BOX 102278 ANCHORAGE, AK 99510-2278 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 P O BOX 196105 ANCHORAGE, AK 99510-6105 ALYESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ALYESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 ANCHORAGE DALLY NEWS, EDITORIAL PG EDTR MICHAEL CAREY P O BOX 149001 ANCHORAGE, AK 99514 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL P O BOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON P O BOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, P O BOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA)INC, INFO RESOURCE CTR MB 3-2 P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, SUE MILLER P O BOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER P O BOX 772805 EAGLE RIVER, AK 99577-2805 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P O DRAWER 66 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE, AK 99518 JACK O HAKKILA P O BOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE P O BOX 196168 ANCHORAGE, AK 99519-6168 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA)INC, PETE ZSELECZKY LAND MGR P O BOX 196612 ANCHORAGE, AK 99519-6612 AMSI/VALLEE CO INC, WILLIAM O VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE ClR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER P O BOX 1468 KENAI, AK 99611-1468 PENNY VADLA P O BOX 467 NINILCHIK, AK 99639 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, PRESIDENT TONY IZZO P O BOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, KEVIN TABLER P O BOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, MR. DAVIS, ESQ P O BOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 77O471 EAGLE RIVER, AK 99577-0471 RON DOLCHOK P O BOX 83 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN P O BOX 3029 KENAI, AK 99611-3029 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASlLLA, AK 99654-5751 PACE, SHEILA DICKSON P O BOX 2018 SOLDOTNA, AK 99669 JAMES GIBBS P O BOX 1597 SOLDOTNA, AK 99669 KENAI NATL WILDLIFE REFUGE, REFUGE MGR P O BOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ PIONEER, P O BOX 367 VALDEZ, AK 99686 ALYESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK P O BOX 300 MS/701 VALDEZ, AK 99686 VALDEZ VANGUARD, EDITOR P O BOX 98 VALDEZ, AK 99686-0098 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 RICK WAGNER P O BOX 6O868 FAIRBANKS, AK 99706 FAIRBANKS DALLY NEWS-MINER, KATE RIPLEY P O BOX 70710 FAIRBANKS, AK 99707 C BURGLIN P O BOX 131 FAIRBANKS, AK 99707 FRED PRATT P O BOX 72981 FAIRBANKS, AK 99707-2981 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 K&K RECYCL INC, P O BOX 58055 FAIRBANKS, AK 99711 ASRC, BILL THOMAS P O BOX 129 BARROW, AK 99723 RICHARD FINEBERG P O BOX 416 ESTER, AK 99725 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL P O BOX 755880 FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 INDEX CONSERVATION ORDER NO. 457 AURORA OIL POOL 1) May 24, 2001 2) May 24, 2001 3) June 15, 2001 4) June 21,2001 s) 6) July 24, 2001 7) July 23,2001 8) July 24, 2001 9) July 31,2001 10) August 15, 2001 11) August 17, 2001 12) Sign In Sheet for Meeting between AOGCC/BP Aurora Pool Rules and AIO, Confidential Exhibit II-6 VI-10, VI-13, Vl-14, VI-15, VI-16 in Conf room Aurora Pool Rules and AIO Notice of Hearing, Affidavit of Publication, mailing list E-mail between T. Maunder and Gordon Pospisil Sign In Sheet for hearing Supplemental Data - Aurora Pool Rules and AIO Confidential Supplementl, Exhibit VI-1 through VI-9 in Conf Room Transcript (Confidential portion in Conf Room) Second Supplemental Data - Aurora Pool Rules and AIO Oversized Display Exhibit VI-17, VI-17A, VI-17B, Map Al, A2, A3 HCPF, Map B7L, B7L, B7U, CP and Map 101113 in Confidential Room Letter from Phillips to AOGCC Various e-mails CO 457 #12 RE: FW: Aurora Pool Information Request {" Subject: RE: FW: Aurora Pool Information Request Date: Thu, 16 Aug 2001 11:09:41 -0500 From: "Pospisil, Gordon" <PospisG~BP.com> To: "'Robert Crandall'" <Bob_Crandall~admin.state.ak.us> Bob, Yes, we will forward recent Aurora well pressures as discussed. These should be sent to you on Monday with a transmittal letter. You should receive MPU data from Janet Weiss this week. Gordon ..... Original Message ..... From: Robert Crandall [mailto:Bob_Crandall0admin.state.ak.us] Sent: Tuesday, August 14, 2001 11:46 AM To: Pospisil, Gordon Cc: Seamount, Dan Subject: Re: FW: Aurora Pool Information Request Gordon: I e-mailed Steve and Janet as we discussed. We also discussed pressure data the last time we talked. Do you want to submit any additional pressure data from the Aurora area? Bob Crandall "Pospisil, Gordon" wrote: > Bob, > Thanks again for the clarification as to the basis for the Commission's > requests for KRU and MPU data. > As we discussed, if the Commission requires information from MPU and KRU > owners, please make requests directly to operator representatives for KRU > and MPU. > > The Aurora owners have provided supplemental data on the area within PBU as > requested by the Commission to support a timely decision on the Aurora Pool > Rules and Area Injection Operations. We are available to discuss this > supplemental data further if necessary. > > Thanks again. > Gordon > Gordon Pospisil > (907) 564-5769 > pospisg~bp, com > > ..... Original Message ..... > From: Robert Crandall [mailto:Bob_Crandall~admin.state.ak.us] > Sent: Friday, August 03, 2001 10:01 AM > To: Pospisil, Gordon > Subject: Re: FW: Aurora Pool Information Request > > Gordon: > Thanks for your reply, I appreciate the candor. Let me try to explain > my understanding of the request for data on the initial conditions from > the KRU and MPU in considering your petition for pool rules at Aurora. I of 4 8/16/2001 1:02 PM RE: FW: Aurora Pool Information Request i'" > Briefly summarized your application indicates that the primary > justification for considering Aurora a separate pool from Borealis is > due to unique fluid contacts, api gravities and pressures in each of the > areas. Also that the pool area could be established based on presently > known oil water contacts and Kuparuk River Formation structure. > These are reasonable interpretations but they need to be evaluated in > the context of what has been established from the adjacent Kuparuk River > Oil Pool in the MPU and KRU. The Commission request for information on > the range of initial conditions (o/w contacts, api gravities, and > pressures) is based on these areas being appropriate analogues to > Aurora. The gross characteristics of the producing formation are very > similar between these areas, importantly the structural history of the > two areas, particularly normal faulting related to subsidence of the > Barrow Arch is very similar and the oil accumulations are commonly > thought to be genetically related. > You are probably correct in asserting that the information we have > requested could be obtained from other sources, but I believe our > purpose for doing so in the hearing is to have this information included > in the record of the Commission's order. > My comments regarding the initial pressures from Aurora and Borealis > deserve some clarification. In the hearing RFT data was used to > characterize the initial pressures, are there static or PBU data which > are representative of initial conditions also? > I hope this is useful. > Bob Crandall > > "Pospisil, Gordon" wrote: > > > > ..... Original Message ..... > > From: Pospisil, Gordon > > Sent: Thursday, August 02, 2001 8:38 AM > > To: 'Crandall~admin.state.ak.us' > > Subject: FW: Aurora Pool Information Request > > Importance: High > > > > Bob, > > > > BP is very interested in addressing questions posed by you and the > > Commissioners as part of the Aurora Pool Rules submission to allow your > > timely decision and findings. I'm responding via email but am also ready > to > > discuss your questions either by phone or in person. > > > > In summary, given our prehearing meeting with Commission staff on June 15 > > where we discussed the proposed Aurora Pool Rules boundary, we were a bit > > surprised by the direction and extent of questions at the hearing. > However, > > we've included extensive data well beyond the proposed Pool area to assist > > in your review. The intent of the Commission is not clear in requesting > > data for areas within existing Pools and in other Units. > > As you might understand, BP as operator of the proposed Aurora Pool does > not > > represent the owners or operators of Kuparuk River Unit or Milne Point 2 of 4 8/16/2001 1:02 PM RE: FW: Aurora Pool Information Request ,,,,,' > Unit > > and is not in a position to provide additional data from those Units. > > Although, it would appear that the data of interest is most likely > available > > to you through routine reporting by those Units or can be obtained by you > > through direct requests. > > Let me respond more specifically to your email questions below (as > > attached). > > 1) regarding item (1) we've submitted data on API gravities as measured; >it > > is subject to interpretation as to which samples are "black oil." We have > > no further data or interpretation to offer. > > 2) we've included all representative data to describe initial pressures by > > area; other pressure data, i. e., PBU or statics have or will be reported > > with routine well reports; however, given that production/depletion has > > commenced, this data may not be representative of initial pressure > > conditions. > > 3) regarding item 3) we've submitted data as made available to BP by > > operator Phillips. If the commission needs additional data from the KRU, > > they will need to request it from Phillips. > > 4) regarding the MPU data, Aurora owners do not own and are not privileged > > to share MPU data and therefore cannot provide it as part of the Aurora > Pool > > Rules submission. > > > > Again, I would like to discuss your questions further if needed to fully > > address your concerns. > > > > Please give me a call. > > > > Gordon > > 564-5769 > > > > EMAIL AS FORWARDED: > > Fred: > > > > We received a package of information titled Aurora Pool Rules and Area > > Injection Application-Second Supplement, dated July 31, 2001 that > > includes some of the information I requested you include in your > > testimony at the Aurora pool rules and area injection order hearing. > > Prior to the hearing I asked that you include in your testimony a > > comparison of the initial conditions from the Kuparuk River Oil Pool in > > the Kuparuk River Unit, specifically the range of initial pressures, api > > gravities, and oil-water contacts, with those observed in the Aurora and > > Borealis proposed Oil Pools in the Prudhoe Bay Unit. > > > > The information we received yesterday regarding my pre-hearing request > > is not entirely adequate, let me explain; > > 1) The comparison of API gravity ranges for the three areas should be > > for black oil. The range of API gravities shown for the Aurora area > > appears to indicate a continuum from 25 to 47 API. Actually this > > represents a narrow range of black oil API's in the mid twenties and a > > single sample of gas condensate in the mid forties. The range of API we > > wish to evaluate from the three areas are those associated with black > > oil only. ~ of 4 8/16/2001 1:02 PM RE: FW: Aurora Pool Information Request 2) The pressure data data from Aurora and Borealis included only rft data and does not included any other kinds of pressure measurements. Have there been on other kinds of pressure measurements made in these areas? If not, why not? If there have been other kinds of pressure measurements made in these areas they should be included in the comparison, each type of measurement should be identified for example, static bottomhole surveys should be distinguishable from rft's. 3) The pressure data from the Kuparuk River unit is represented as a single point. Again we interested in understanding the range of initial pressures observed in the Kuparuk River Oil pool in the Kuparuk River Unit. To do this one needs to understand the distribution of hydraulic units and timing of the onset of production from each of these pressure compartments. Does the information we received on July 31 indicate a contention on your part that there was no variation in initial pressure throughout the Kuparuk river Unit? If so please submit the data set you analyzed to reach this conclusion. If not please plot the range of initial pressure for each hydraulic unit within the Kuparuk River Unit Kuparuk River Oil Pool, and identify as to type of pressure measurement. In the hearing Commissioner Heusser asked for the range of initial pressures, API gravities (black oil), and oil water contacts for the Milne Point Unit, Kuparuk River Oil Pool. These data were not included in the July 31 submittal and are required for our evaluation of your requests. To summarize the pressure and API gravity data should be from discrete hydraulic units prior to significant production or injection and should be comparable with those described above. If you have any questions or comments please call me at 793-1230. Thanks Bob Crandall of 4 8/16/2001 1:02 PM RE: Request for Information Relating to Aurora Pool( ' ' -s Subject: RE: Request for Information Relating to Aurora Pool Rules Date: Wed, 15 Aug 2001 18:26:13 -0500 From: "Weiss, Janet L" <WeissJL2~BP.com> To: "'Robert Crandall"' <Bob_Crandall~admin.state.ak.us>, "Weiss, Janet L" <WeissJL2~BP.com> C C: "S eamount, Dan" <dan_seamount~admin. state, ak.us> Bob: We are putting the information in the mail now. When you get the data/information, please let me know if you need anything else. Janet Weiss ACT! Assetwide Reservoir Planning Team Lead ..... Original Message ..... From: Robert Crandall [mailto:Bob_Crandall0admin.state.ak.us] Sent: Tuesday, August 14, 2001 11:23 AM To: weissjl2@bp.com Cc: Seamount, Dan Subject: Request for Information Relating to Aurora Pool Rules Janet: I was given your name by Gordon Pospisil as a contact for some data on the initial conditions of the Milne Point Unit, Kuparuk River Oil Pool. This information is required by the AOGCC in order to evaluate portions of BP's testimony during the Aurora Pool Rules Hearing (PBU Kuparuk River Fm.), which was held last month. Specifically we are requesting information on the range of initial conditions observed in the Milne Point Unit Kuparuk River Formation. We are interested in the range of o/w contacts, api gravities, and pressures which existed initially across the unit. A map of the presently delineated hydraulic units in the Kuparuk River Formation is also requested. Please give me a call at 793-1230 if you'd like to discuss this. Thanks Bob Crandall I of 1 8/16/2001 1:03 PM Request for information relating to Aurora Pool Rule{- Subject: Request for information relating to Aurora Pool Rules Date: Tue, 14 Aug 2001 11:42:06 -0800 From: Robert Crandall <Bob_Crandall~admin.state.ak.us> Organization: DOA-AOGCC To: sbross@ppco.com C C: "S eamount, Dan" <dan_seamount~admin. state, ak.us> Steve: I was given your name by Gordon Pospisil as a contact for some data on the initial conditions of the Kuparuk River Unit, Kuparuk River Oil Pool. This information is required by the AOGCC in order to evaluate portions of BP's testimony during the Aurora Pool Rules Hearing (PBU Kuparuk River Fm.), which was held last month. Specifically we are requesting information on the range of initial conditions observed in the Kuparuk River Unit, Kuparuk River Formation. We are interested in the range of o/w contacts, api gravities, and pressures which existed initially across the unit. A map of the presently delineated hydraulic units in the Kuparuk River Formation is also requested. Please give me a call at 793-1230 if you'd like to discuss this. Thanks Bob Crandall I of 1 8/16/2001 1:03 PM Request for Information Relating to Aurora Pool Rul¢~ Subject: Request for Information Relating to Aurora Pool Rules Date: Tue, 14 Aug 2001 11:23:19 -0800 From: Robert Crandall <Bob_Crandall~admin.state.ak.us> Organization: DOA-AOGCC To: weissjl2~bp.com CC: "Seamount, Dan" <dan_seamount@admin.state.ak.us> Janet: I was given your name by Gordon Pospisil as a contact for some data on the initial conditions of the Milne Point Unit, Kuparuk River Oil Pool. This information is required by the AOGCC in order to evaluate portions of BP's testimony during the Aurora Pool Rules Hearing (PBU Kuparuk River Fm.), which was held last month. Specifically we are requesting information on the range of initial conditions observed in the Milne Point Unit Kuparuk River Formation. We are interested in the range of o/w contacts, api gravities, and pressures which existed initially across the unit. A map of the presently delineated hydraulic units in the Kuparuk River Formation is also requested. Please give me a call at 793-1230 if you'd like to discuss this. Thanks Bob Crandall of 1 8/16/2001 1:03 PM file:///Untitled "Young, Jim" wrote: Jane, The Kuparuk River Formation at the Aurora Oil Pool is overlain by the Kalubik, HRZ/CM1 shales, which have a combined thickness of approximately 150-268 feet in the S-pad area. Mechanical properties determined from dipole sonic log and core data in well S- 104 for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.83 to 0.92 psi/fi. In order to stay below the breakdown pressure of the above mentioned formations & assure that produced water injection will be contained in the Kuparuk formation, maximum bottom-hole injection pressure in the Aurora Pool will be limited to 0.83 psi/fi. At the datum depth of 6700'ss, this is approximately 5500 psi BHIP. Since the hydrostatic head provided by 0.442 psi/ft injection water is 2961 psi, surface injection pressure will need to be limited to 2600 psi if the Kupurak injection rate is less than 2000 BWPD. In wells with >2000 bwpd Kupurak injection rates, friction pressures are expected to exceed 100psi, and would allow surface pressure to be increased without exceeding 5500 psi bottom-hole injection pressure. Based on hydraulic modelling and pressure match data from the recent S-101i step-rate tests, only in extremely rare cases (3-1/2" tubing and rates > 8200 BWIPD) would friction pressures be high enough to allow 3000psi surface pressure. Thanks, Jim Young PE, GPB New Developments youngj3@bp.com (907) 564-5754 fax 5016 I of 1 9/4/01 5:02 PM Re: [Fwd: FW: Aurora Pool Infbrmation Request] ~' ~ ~ . Subject: Re: [Fwd: FW: Aurora Pool Information Request] Date: Sun, 19 Aug 2001 13:53:37 -0800 From: "Camille O. Taylor" <Cammy_Taylor~admin.stat¢.ak.us> Organization: DOA-AOGCC To: Robert Crandall <gob_Crandall~admin.state.ak.us> CC: Dan Seamount <dan_seamount~admin.state.ak.us>, Julie Heusser <julie_heusser~adrnin.state.ak.us>, "Jody, V'the real Chair\", Colombie" <jody_colombie~admin.state.ak.us> Bob, as I mentioned the other day, the e-mails provide a written record of our correspondence back and forth. Please be sure that Jody gets all e-mails that are actually part of the administrative record. Thanks, Cammy Robert Crandall wrote: > Cammy: > > Is it proper for elements of a hearing record to be corresponded about > in e-mail like this? > > RPC > > Subject: RE: FW: Aurora Pool Information Request Date: Thu, 16 Aug 2001 11:09:41 -0500 From: "Pospisil, Gordon" <PospisGSBP. corn> To: "'Robert Crandall'" <Bob CrandallSadmin.state.ak. us> Bob, Yes, we will forward recent Aurora well pressures as discussed. These should be sent to you on Monday with a transmittal letter. You should receive MPU data from Janet Weiss this week. Gordon ..... Original Message ..... From: Robert Crandall [mailto:Bob Crandall~Sadmin.state.ak. us] Sent: Tuesday, August 14, 2001 11:46 AM To: Pospisil, Gordon Cc: Seamount, Dan Subject: Re: FW: _~lJlD22~.-Pool Information Request Gordon: I e-mailed Steve and Janet as we discussed. We also discussed pressure data the last time we talked. Do you want to submit any additional pressure data from the Aurora area? Bob Crandall "Pospisil, Gordon" wrote: > > Bob, > Thanks again for the clarification as to the basis for the Commission's > requests for KRU and MPU data. > > As we discussed, if the Commission requires information from MPU and KRU > owners, please make requests directly to operator representatives for KRU > and MPU. I of 4 8/20/01 11:40 AM Re: [Fwd: FW: Aurora Pool Information Request] > > The Aurora owners have provided supplemental data on the area within PBU as > requested by the Commission to support a timely decision on the Aurora Pool > Rules and Area Injection Operations. We are available to discuss this > supplemental data further if necessary. > > Thanks again. > Gordon > > Gordon Pospisil > (907) 564-5769 > pospisgSbp, corn > > ..... Original Message ..... > From: Robert Crandall [mailto:Bob CrandallSadmin.state.ak. us] > Sent: Friday, August 03, 2001 10:01 AM > To: Pospisil, Gordon > Subject: Re: FW: Aurora Pool Information Request > > Gordon: > > Thanks for your reply, I appreciate the candor. Let me try to explain > my understanding of the request for data on the initial conditions from > the KRU and MPU in considering your petition for pool rules at Aurora. > > Briefly summarized your application indicates that the primary > justification for considering Aurora a separate pool from Borealis is > due to unique fluid contacts, api gravities and pressures in each of the > areas. Also that the pool area could be established based on presently > known oil water contacts and Kuparuk River Formation structure. > > These are reasonable interpretations but they need to be evaluated in > the context of what has been established from the adjacent Kuparuk River > Oil Pool in the MPU and KRU. The Commission request for information on > the range of initial conditions (o/w contacts, api gravities, and > pressures) is based on these areas being appropriate analogues to > Aurora. The gross characteristics of the producing formation are very > similar between these areas, importantly the structural history of the > two areas, particularly normal faulting related to subsidence of the > Barrow Arch is very similar and the oil accumulations are commonly > thought to be genetically related. > > You are probably correct in asserting that the information we have > requested could be obtained from other sources, but I believe our > purpose for doing so in the hearing is to have this information included > in the record of the Commission's order. > > My comments regarding the initial 'pressures from Aurora and Borealis > deserve some clarification. In ~he hearing RFT data was used to > characterize the initial pressures, are there static or PBU data which > are representative of initial conditions also? > > I hope this is useful. > Bob Crandall > > "Pospisil, Gordon" wrote: > > ..... Original Message ..... > > From: Pospisil, Gordon > > Sent: Thursday, August 02, 2001 8:38 AM > > To: 'CrandallSadmin.state.ak. us' 2 of 4 8/20/01 11:40 AM Re: [Fwd: FW: Aurora Pool Information Request]{' > > > Subject: FW: Aurora Pool Information Request > > > Importance: High > > > Bob, > > > BP is very interested in addressing questions posed by you and the > > > Commissioners as part of the Aurora Pool Rules submission to allow your > > > timely decision and findings. I'm responding via email but am also > rea dy >>to > > > discuss your questions either by phone or in person. >>> > > > In summary, given our prehearing meeting with Commission staff on June > 15 > > > where we discussed the proposed Aurora Pool Rules boundary, we were a > bit > > > surprised by the direction and extent of questions at the hearing. > > However, > > > we've included extensive data well beyond the proposed Pool area to > assist > > > in your review. The intent of the Commission is not clear in requesting > > > data for areas within existing Pools and in other Units. >>> > > > As you might understand, BP as operator of the proposed Aurora Pool does > > not > > > represent the owners or operators of Kuparuk River Unit or Milne Point > > Unit > > > and is not in a position to provide additional data from those Units. > > > Although, it would appear that the data of interest is most likely > > available > > > to you through routine reporting by those Units or can be obtained by > you > > > through direct requests. >>> > > > Let me respond more specifically to your email questions below (as > > > attached). >>> > > > 1) regarding item (1) we've submitted data on API gravities as measured; >>it > > > is subject to interpretation as to which samples are "black oil." We > have > > > no further data or interpretation to offer. > > > 2) we've included all representative data to describe initial pressures > by > > > area; other pressure data, i. e., PBU or statics have or will be > reported > > > with routine well reports; however, given that production/depletion has > > > commenced, this data may not be representative of initial pressure > > > conditions. > > > 3) regarding item 3) we've submitted data as made available to BP by > > > operator Phillips. If the commission needs additional data from the > KRU, > > > they will need to request it from Phillips. > > > 4) regarding the MPU data, Aurora owners do not own and are not > privileged > > > to share MPU data and therefore cannot provide it as part of the Aurora > > Pool > > > Rules submission. > > > Again, I would like to discuss your questions further if needed to fully > > > address your concerns. >>> > > > Please give me a call. 3 of 4 8/20/01 11:40 AM Re: [Fwd: FW: Aurora Pool Information Request]i > > > Gordon > > > 564-5769 > > > EMAIL AS FORWARDED: > > > Fred: > > > We received a package of information titled Aurora Pool Rules and Area > > > Injection Application-Second Supplement, dated July 31, 2001 that > > > includes some of the information I requested you include in your > > > testimony at the Aurora pool rules and area injection order hearing. >>> > > > Prior to ~he hearing I asked that you include in your testimony a > > > comparison of the initial conditions from the Kuparuk River Oil Pool in > > > the Kuparuk River Unit, specifically the range of initial pressures, api > > > gravities, and oil-water contacts, with those observed in the Aurora and > > > Borealis proposed Oil Pools in the Prudhoe Bay Unit. > > > The information we received yesterday regarding my pre-hearing request > > > is not entirely adequate, let me explain; > > > 1) The comparison of API gravity ranges for the three areas should be > > > for black oil. The range of API gravities shown for the Aurora area > > > appears to indicate a continuum from 25 to 47 API. Actually this > > > represents a narrow range of black oil API's in the mid twenties and a > > > single sample of gas condensate in the mid forties. The range of API we > > > wish to evaluate from the three areas are those associated with black > > > oil only. > > > 2) The pressure data data from Aurora and Borealis included only rft > > > data and does not included any other kinds of pressure measurements. > > > Have there been on other kinds of pressure measurements made in these > > > areas? If not, why not? If there have been other kinds of pressure > > > measurements made in these areas they should be included in the > > > comparison, each type of measurement should be identified for example, > > > static bottomhole surveys should be distinguishable from rft's. > > > 3) The pressure data from the Kuparuk River unit is represented as a > > > single point. Again we interested in understanding the range of initial > > > pressures observed in the Kuparuk River Oil pool in the Kuparuk River > > > Unit. To do this one needs to understand the distribution of hydraulic > > > units and timing of the onset of production from each of these pressure > > > compartments. Does the information we received on July 31 indicate a > > > contention on your part that there was no variation in initial pressure > > > throughout the Kuparuk river Unit? If so please submit the data set you > > > analyzed to reach this conclusion. If not please plot the range of > > > initial pressure for each hydraulic unit within the Kuparuk River Unit > > > Kuparuk River Oil Pool, and identify as to type of pressure measurement. >>> > > > In the hearing Commissioner Heusser asked for the range of initial > > > pressures, API gravities (black oil), and oil water contacts for the > > > Milne Point Unit, Kuparuk River Oil Pool. These data were not included > > > in the July 31 submittal and are required for our evaluation of your > > > requests. To summarize the pressure and API gravity data should be from > > > discrete hydraulic units prior to significant production or injection > > > and should be comparable with those described above. > > > If you have any questions or comments please call me at 793-1230. > > > Thanks > > > Bob Crandall 4 of 4 8/:20/01 ! 1:40 AM #11 PHILLIPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August17,2001 Mr. Bob Crandall Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Crandall: Based on your request for certain Kuparuk River Unit data, I have compiled the following information. Per our discussion, the release of confidential interpreted data that is not in the public domain will require approval of the Kuparuk River Unit working interest owners and a confidentiality agreement. Hence, the submitted data is currently in the public domain. The pressure and APl data are based on pressure surveys, which are reported to the AOGCC. Information about an oil-water contact is from public testimony and an AAPG bulletin. Initial Pressures Attachment 1 is a graph of bottom-hole shut-in pressures adjusted to a datum of 6,200 feet sub-sea for well tests performed prior to field start-up. The abscissa identifies the well, date, type of test and interval tested. This should supply you with the range of pressures available. As you can see from the graph, there are potentially some invalid pressures on the two ends of the graph. Initial Oil Gravities Attachment 2 uses that same data set and shows the reported APl oil gravities from the same wells pdor to start-up. The average gravity, as shown on the graph, is 24°APl, which is also reported as the average oil gravity in Attachment 3. . Oil-Water Contacts Included are two examples of public information on the oil-water contact within the Kuparuk River Unit. First, Kuparuk River Field testimony before the AOGCC on March 25, 1981, presented by William H. McMillian states the following: "The water-oil contact has not been observed in any individual sand members of Kuparuk wells. Since the highest occurrence of water was in the West Sak No. 6 well and -6539 feet sub-sea elevation and other wells have encountered hydrocarbons at deeper sub- sea elevations, it is interpreted that the water-oil contact is a tilting surface with a slight north dip." The second, Attachment 3, Geology and Regional Setting of Kuparuk Oil Field, AlaSka, by George Carmen and Peter Hardwick (AAPG Bulletin, v 67, num. 6, June 1983) finds that "... an oil-water contact has not been observed within a single, clean reservoir lithology because of thin beds. However, the contact has been determined to exist between approximately - 6,530 ft in the south and at least -6,700 ft in the north. Furthermore, observations of oil and water levels in 15 wells in the eastern field area suggest that this oil-water contact has a uniform tilt of about 0.5° toward the north-northeast. However, the possibility of a step-faulted contact cannot be discounted without additional data. The tilt is thought to have resulted from the inability of the reservoir fluids to equilibrate during the Tertiary to present-day northeastward tilting of the Alaska Arctic plain." The suggested oil-water contact is depicted in Figure 9 of Attachment 3. Any additional information, especially currently confidential information, will require more time and potentially working-interest owner approval. Please call me with any questions you have regarding this data. Sincerely, Biaden Kuparuk River Unit Surveillance Engineering Supervisor Cc: Don Ince Gordon Pospisil, BP RECEIVED / U6 ?, 0 ?_001 Alaska Oil & Gas Cons. Commission, Anchorage Kuparuk River Unit Pressures at 6200 ft SS prior to start-up 3350 3300 3250 '-' 3200 3150 3100 O I1'1 Z -I Kuparuk River Unit Api Gravity prior to start-up 30. Average gravity = 24°APl Il il - II 25. 20. 15. 10. O. , 0 'l- Z ~I~ TTACHMENT l he American Association of Pelloleum G¢ologisl$ Bulletin · V. 67. No. 6 (June 1983). E 1014-~00, 14 Figs. 3 Geology and Regional Setting of Kuparuk Oil Field, Alaska' GEORGE J. CARMAN2 and PETER HARDWICK3 ABSTRACT The Kuparuk oil field is located on the Alaskan Arctic plain in the Colville-Prudhoe basin, 10 to 30 mi (16 to 48 km) west of the Prudhoe Bay field. The 240 API crude is similar in type to that in the Permo-Triassic reservoirs in the Prudhoe Bay field; however, it is from the Lower Cre- taceous Kuparuk Formation. This reservoir is located in a basin between the Colville and Prudhoe highs. The origin of the oil is believed to be predominantly Lower sequence formations with migration occurring possibly via the Prudhoe Bay field. The dominant trapping mechanism is stratigraphic pinch-out and truncation of the reservoir at a local uncon- formity along the southern and western flanks of a southeast-plunging antiform. Structural dip closure exists along the northern and eastern flanks. The reservoir sand- stones occur within sequences which become cleaner and coarser upward, and are thought to be shallow marine in origin with a provenance to the northeast. They are inter- preted to be infrarift sediments on what is now a passive, Atlantic-type continental margin. Two of the four major lithostratigraphic units mapped within the Kuparuk For- mation exhibit good reservoir characteristics and extend over an area in excess of 200 mi2 (518 kin2). The cumulative net pay in the Kuparuk field ranges up to 90 ft (27 m), and the estimate of movable oil-in-place is 4.4 billion stock tank bbl. There is no gas cap. The field exhibits a variable oil-water contact ranging from -6,550 ft (-1,990 m) in the southeast to -6,700 ft (-2,042 m) in the north. After secondary waterflooding, the potential recover- able reserves are estimated to be about 1.0 to 1.5 billion stock tank bbl. Kuparuk field, therefore, ranks as one of the largest oil fields in the United States. ©Copyright 1983. The American Association ol Petroleum Geologists. All rights reserved. 1Manuscrip! received, May 6, 1982; accepted, May 27, 1982. Presented at the annual AAPG convention, Calgary, Alberta, Canada, June 1982. 2BP Alaska Exploration Inc,, I Maritime Plaza, Suite 500, San Francisco, California 94111. Current address: Southeastern Oil & Gas Pty. Ltd., 16160 Albert Road, South Melbourne, Victoria, Australia 3205. 3BP Alaska Exploration Inc., I Maritime Plaza, Suite 500, San Francisco, California 94111. Current address: BP Petroleum Development of Spain, S.A., Cea Bermfidez, 66 Madrid-3, Spain. The writers thank the management of BP Alaska Exploration. Inc., Sohio Alaska Petroleum Co., and the Allantic Richfield Co. for permission lo publish this paper. We would also like to express our indebtedness to all past and present Kuparuk colleagues. We particularly thank A. Knight and D. Wharton for their specialist contributions lo the sedimentology and stratigraphy We are grateful for Pamela Demory's typing and editorial assistance in preparing the manuscript and for the workmanship of Ron Stefanich who drafted the figures. INTRODUCTION The Kuparuk oil field is located at the northern edge of the Alaskan North Slope about 260 mi (418 kin) north of the Arctic Circle. Its history of discovery and appraisal has been overshadowed by the operations associated with its neighbor, the Prudhoe Bay field, which is only 10 to 30 mi (16 to 48. km) to the east (Fig. 1). Following the announcement of the Prudhoe Bay field discovery in January 1968, the oil industry dramatically increased its exploration activity to evaluate the then remaining unleased acreage between the Canning and Col- ville Rivers on the Arctic plain. By the time of the 23rd State Lease Sale in September 1969, about 35 exploration wells had been drilled, chiefly with the primary objective of pre-Cretaceous reservoirs subcropping a major uncon- formity as at the Prudhoe field. Among these wells was the BP Alaska/Sinclair Oil Ugnu State 1 located 30 mi (48 km) west of the Prudhoe discovery well. Ugnu State 1 was notable because, in April 1969, drill-stem test I flowed oil at a rate of 1,056 bbl/day from sandstones in the interval between 6,158 and 6,175 ft (1,877 and 1,882 m) b.r.t. (below rotary table). This marked the discovery of the Kuparuk oil field. Within 2 years of this discovery, a further nine wells had been drilled and had established a correlative sequence over about 400 mi2 (1,036 km2) around the Ugnu well. Fur- ther exploration continued to concentrate on delineating Prudhoe Bay type reservoirs and tended to underplay the significance of the Ugnu discovery. However, BP Alaska Exploration Inc. (BPAE), together with the Atlantic Rich- field Co. (ARCO) and the Sohio Alaskan Petroleum Co. (Sohio), participated in the drilling of more than 25 Kuparuk appraisal wells during the 10-year period from 1970 to 1980. In November 1980, ARCO requested that the Alaskan Oil and Gas Conservation Commission con- sider pool rules for the development and production of the Kuparuk field west of Prudhoe, and the proposed field development rules were presented publically in March 1981. In late 1981, the Kuparuk accumulation was unitized, providing interim working interests of 28.8% for BPAE, 57.5070 for ARCO, 9.6% for Sohio, and the remainder divided among Chevron, Exxon, Mobil, Phil- lips, and Union. BASIN GEOLOGY The principal structural features of the Alaskan Arctic basin are the Barrow arch and the Colville trough (Fig. 2). The Barrow arch, a paleohigh that influenced the deposi- tion of pre-Late Cretaceous sediments, is now located just 1014 George J. Carman and Peter Hardwick 1015 offshore and parallel with the present north Alaskan coastline. The Colville trough is asymmetric with an east- west axis close to the Brooks Range. Its sedimentary sec- tion above economic basement exceeds 30,000 ft (9,144 m). The pre-Cretaceous sediments within this trough are as old as Mississippian and were derived from a northern provenance that probably lay beyond what is now the outer continental shelf. These strata are commonly referred to as the Ellesmerian sequence, after Lerand (1973), or the Lower sequence. The overlying Brookian or Upper sequence (Cretaceous to Tertiary) sediments were derived .largely from the south following a continent- continent collision and consequent uplift of the Brooks Range Mountains. This paper describes the Kuparuk reservoir which occurs within a Lower Cretaceous sequence that represents the period during which the major sediment provenance switched from the north to the south. This sequence, therefore, warrants distinction from the Ellesmerian and Brookian sequences. Because it appears to have been derived locally from the Barrow arch, we here refer to it as the Barrovian sequence. STRATIGRAPHY In addition to the regional tectonic features and proc- esses described above, the deposition of the Barrovian sequence over the Kuparuk oil field was further influenced by the presence of the Colville and Prudhoe highs. These are two local features of the Barrow arch, the presence of which is most evident from the isopachs of the Lower Cre- taceous sediments (Fig. 3). The ensuing section describes the general stratigraphic setting of the Kuparuk field (Fig. 4) and proposes a formal stratigraphic nomenclature for the Lower Cretaceous sequence in the Colville-Prudhoe basin between the Colville and Prudhoe highs. Sagavanirktok Formation The first recognizable formation beneath the surficial glacial outwash and Quaternary gravels (probably of the Gubik Formation) is the Sagavanirktok Formation. It consists of poorly sorted gravel, unconsolidated sand, and mudstone in an interbedded sequence at least 2,000 ft (610 m) thick. The dominant grain component is quartz or quartzite, with rare igneous rock fragments and detrital wood fragments. The lithologies present are similar to those described in outcrops to the south and southeast of the area (Detterman et al, 1975), and were probably depos- ited in a shallow-water environment with a provenance to the south in the Brooks Range uplift area. The Sagavanirktok Formation is of Tertiary age. Coiville Group (Undifferentiated) The Colville Group, which is some 3,000 ft (914 m) thick in the Colville-Prudhoe basin, is informally subdivided into three lithostratigraphic units. The uppermost unit comprises an interbedded sandstone, siltstone, and mud- stone sequence together with rare thin carbonaceous beds. aRCTIC #ILEI FIG. I--Kuparuk field is located about 260 mi (418 km) north of the Arctic Circle on north Alaskan coastal plain. It is linked to Trans-Alaska Pipeline system via 26 mi (42 kin) Kuparuk pipe- line. This upper unit is approximately 900 ft (274 m) thick. It is probably a correlative of the Prince Creek/Schrader Bluff Formations of Late Cretaceous age (Fig. 5), and includes the West Sak sands, informally described by Jamieson et al 0980). The middle unit is a mudstone and siltstone sequence which attains a thickness of about 1,000 ft (305 m). The mudstones are predominantly pale brown, silty, com- monly micaceous, and in places contain disseminated pyrite. In the southern and eastern parts of the Colville- Prudhoe basin, a lower unit is present at the base of the Colville Group. This unit is comprised of a monotonous sequence of tuffaceous mudstone with subordinate silt- stone and sandstone totaling about 1,000 ft (305 m). It has a characteristic gamma-ray response which exceeds 100 API units. This lower unit contains rich assemblages of dinoflagellates and abundant radiolarians, on the basis of which it has been dated as Coniacian to Campanian. The middle and upper units contain only sparse assem- blages of dinoflagellates and radiolafians, in addition to which agglutinating Foraminifera and miospores occur. Mainly on the evidence of pollen types, a Campanian to Paleocene age is suggested for this sequence, although it appears probable that these formations are markedly diachronous. 1016 Kuparuk Oil Field, Alaska 150" C' 140e COL ILL. E ~ TROUGH MILE8~ 0 50 I BROOKS RANGE After Grantz el al, 197'9 FIG. 2--Principal structural features of Alaskan Arctic plain in region of Kuparuk field are Barrow arch and Colvitle trough. The lalter is a Mississippian to Tertiary depocenter with a sedimentary pile in excess of 30,000 ft (9,144 m). Barrow arch is part of a paleos- tructurai high that provided a sedimentary source to pre-Cretaceous, (Ellesmerian) sequence in the Colville trough. Brooks Range and foothills fold belt began to uplift in Early Cretaceous and provided a provenance for Brookian sediments which prograded succes- sively northward out to the present-day site of continental slope. Ugnuravik Group The stratigraphic sequence between 5,580 and 6,793 ft (1,701 to 2,070 m) b.r.t, in the Kuparuk field discovery well, Ugnu State 1, is formally proposed as the type sec- tion for a new lithostratigraphic unit of group status (Fig. 6). The new unit is here named the Ugnuravik Group, after the river of that name (see location on Fig. 3) and from where the Ugnu well name was derived. Ugnuravik is an Eskimo name referring to the "place where ducks are driven and killed" (Orth, 1971). Figure 6 summarizes the lithostratigraphy and some wireline-log responses of this group in the type well. The Ugnuravik Group is mappable over more than 600 mi2 (1,554 km:) in the Colville-Prudhoe basin, where it attains a thickness in excess of 1,500 ft (457 m) (Figs. 3, 7). Palynological studies suggest an early Valanginian to Albian age. The Ugnuravik Group is probably a correla- tive of the Nanushuk Group and Kongakut/Okpikruak Formations of the same age (Fig. 5); however, its contrast- ing lithologies and sedimentary trends warrant a name dis- tinction. Four specific lithostratigraphic units, three worthy of formation status, are recognized in the type section for the Ugnuravik Group and are correlatable across the Colville- Prudhoe basin as illustrated in Figure 7. These are described in detail below. HRZ unit.--The stratigraphic sequence between 5,580 and 5,670 ft (1,701 to 1,728 m) b.r.t, in the Ugnu State 1 well is described as a typical section for this distinctive lith- ostratigraphic unit. The unit is here referred to as the HRZ unit, after current industry usage referring to its recogni- tion as a highly radioactive zone. The HRZ unit is the cor- relative of the upper part of the unnamed shale of Early Cretaceous age depicted in the stratigraphic summaries by Jones and Speers (1975, their Figure 3) and Jamieson et al 0980), and the upper part of the Put River shale infor- mally referred to by Bushnell (1981). Although its age (see below) appears to be equivalent to the lowest part of the Torok Formation west of the Colville high, the lithologic characteristics of the HRZ unit suggest it is more probably a correlative of the Pebble Shale as described by Molenaar (1981) (Fig. 5). The HRZ unit is typically about 200 ft (61 m) thick. It George J. Carman and Peter Hardwick 1017 E A U lOWER CRET&CEOU$ 180PACH$ {ieet) DISCOVERY WELL MIlls FIG. 3--1sopachs (in feet) of Lower Cretaceous sequence beneath Arctic plain display thinning onto Colville and Prudhoe highs south of Barrow arch. Kuparuk oil field is located wilhin Colville. Prudhoe basin between these structures. Also illustrated are loca- tions of Ugnuravik, Kuparuk, and Miluveach Rivers, and Kalubik Creek, whose names have been chosen for new lithostratigraphic nomenclature proposed in this paper. consists of medium gray to black mudstone with highly carbonaceous microlaminations forming a distinctive papery fissility. Source rock analyses have determined a total organic carbon content of 4 to 9% by weight for these rocks (Seifert et al, 1979). The rock matrix contains calcite and clay minerals including limonite which is thought to be replacing pyrite. Traces of quartz silt, woody frag- ments, calcitic Inoceramus shell fragments, and medium to coarse, subrounded, quartz grains with frosted surfaces characteristically occur within the HRZ unit. Probably the most dominant characteristic of this unit is its exceptionally high radioactivity. Gamma ray spectra- logs from Prudhoe Bay field wells have shown this to be due to the presence of uranium and thorium, which are believed to be concentrated in organic material and finely disseminated throughout the matrix. The top of the 14RZ unit is therefore picked on open-hole logs where the gamma-ray log consistently surpasses 150 APl units (Fig. 7). Stable carbon isotope analyses of kerogen from the 14 RZ unit have yielded {513C values of-27 ppm to-26 ppm, which suggest a marginal marine environment of deposition. The presence of calcitic shell fragments and wood fragments also indicates deposition above the calcium compensation depth and proximity to a plant-supporting landmass. Fur- thermore, the microlaminations, the absence of bioturba- tion, and the high organic carbon content implies an anoxic environment for this black shale facies. As will be shown below, the HRZ unit occurs at the top of a con- formable sequence that infilled and eventually, by the time of HRZ deposition, buried an Early Cretaceous topogra- phy. The HRZ is therefore believed to have been deposited on a shallow, sediment-starved marine shelf similar to that considered for the Pebble Shale (M'olenaar, 1981) and for some other transgressive black shales in North America (Tourtelot, 1979). In the Kuparuk-Prudhoe field area, the HRZ unit con- tains dinoflagellates and radiolarians indicative of an Apt- lan to Albian age. The contact between the HRZ and the overlying lower unit of the Colville Group appears to be a 1018 Kuparuk Oil Field, Alaska COL VILLE COL VILL E-PRUD HOE P R UD H O E HIGH TROUGH HIGH WES T EA $ T ~ ,r[.s,c~rNr : .:,_.:,...:.:.~.._:..,:'.: ,', ',..,.: .'. ,-.: OUB~ FMN' .'.L',~_::-.'o"'.'~'~0,'. ........... ............. .......... P~OC~.N[ __ ~: -.; '.- -~_ ~j .... ., '..~'~'-'' .,] .. ............ . ....... ', .:2 ' ~ O~[N~ ~;, --~ SAGAVANIRKTOK FORMATION ..... i ~:-'..',.'.. ~:..{'.:.-.. .... ':'-' ."~ .--'---'-' .~, _ . ~ ~ ._ .. -:...:'..', -. . .. ... EOCCNE ~'._ ~1 · -~ -e ..... ' ......... O - '-, .... ~ .... '~" fill .... - --~,, ,. ~, , ,: .... .~. -,. ,..., ,. .o ~,. : '.'* ~ .... ,'' 0 , ~ , , , , . UAF STRICI t HAH , , ~.'.'~.~ m.:' : .' ::~.',.~.',','..'.' ~;.'.i'~.' ,' ,t~ ., ~'.~...:.?.. ~;.~ ~ '":¢:?.":".'/:.;::::i.[(:,".':'.'.?.'.'.::.':"~ix':'"'Y:'.':.' <..:....,.;.'.'..~:.:~;~~:,:~).~'.~;:.:..::.:::;.' sa. ro~u ;2~'.: ';. ',.' .;..'.:. -" ' '" ., ........... ~ CONIACIAN .......... . ................. ~ ,.- ~.~ ,, ' ~ ..... ~_ ~__ _ ~_ ~ _ ~ .... ~-?:~:;::~:;_~_-~=4_-_ _=~ ~ YURON{AN Highly condeflled of lbleflce by nondepoi~n or Moi~n -- CENOMANIAN _ _ _ _ __ - _ _ - _ _~-:~_ _ :~ ...... A{ BlAH ~. ., ,. , ..... -' , .... VAI ANGINIAN B[RRIA~IAN Abaence by lrollOn Absence by erosion DTHONIAN KiMM[RiDGiAN CALL, OViAN" Abliace by Z BATHON'~N ~' ~ ( BAJOCIAN _ AA[ ENtT~RC pt iENSBACHiA~ ..... KINQAK 8HALE~ .......... ~ Abeen~e by S~N[UUR~AN ..... .......... ~ erom~n ~ (F TTANOiAN .......... ~ mmmmmm~ ~ R.~;;~ ...... ~,.' , .~ ..... ;: .,..'.*:. ~AQ RIVER FMN '. ~:~ :..: '..,,- .~ ' ,, ...... :..~.'..',.,: ..,.~... ':.~..%. ~; ,; .'..-. ~ ... ...... ,. . · .,. ~ *. . .Z,m.*.,...~.... i m z ' 1' m m ~ m m ] i b z m m I m · . m i ~t, i i . i .i i m ~ _ ~; i ' ' ' m " i ms IJ i i m ] . · z · ., i I I & i ,~ : & I I I I II I I I FIG. 4--Schematic time-stratigraphic section from west to cas! across Colville-Prudhoe basin shows that hiatuses occur both above and below Lower Cretaceous sequence. Ugnuravik Group (defined in Fig. 6) is believed to have had a local northeastern sedimentary provenance and is described as a Barrovian ,sequence to distinguish il from Brookian and Ellesmerian sequences. hiatus, or at least a highly condensed section in which it has not been possible to identify Cenomanian and Turo- nian sediments. However, west of' the Colville high, this condensed zone appears to pass into a conformable sequence of this age. Kalubik Formation.raThe stratigraphic sequence between 5,670 and 5,890 ft (1,728 and 1,795 m) b.r.t, inthe Ugnuravik type section is formally proposed as the type section for a new lithostratigraphic unit which is here named the Kalubik Formation. It is named after the Kalu- George J. Carman and Peter Hardwick 1019 ~; NORTHWESTERN NORTHEASTERN COLVILLE- UJ ALASKA ALASKA PRUDNOE I-- BASIN ~l~ (MolBrdaBr, I001; ~ Carter il ii 1977I(Datlirm&n, 10771 (This Plperl ~OUTH NORTH~'OUTN HOBTH BOURN NORTH QUAT. ' SURFICIAL DEPOSITS SURFICIAL DEPOSITS SURFICIAL DEPOSITS GUBIK FORMATION GUBIK FORMATION GUBIK FORMATION ~ ~ SAGAVANIRKTOK ~ ~ FORM&TION COL VlLL~ GROUP ~ S ,,,,,, ,,. S ,~,,, ,,. ~ NANUSHUK GROUP NANUSHUK GROUP ~ BATHTUB ~ GRAYWACKE ~ ~ PEBBLE ~HALE MB. KAL F 0 ~AMDITOME MB. ~ KINGAK SHALE ~ KINGAK SHALE , , ,, ,, . FIG.. 5--Comparison of lithostratigraphic sequences within and around Colville-Prudhoe basin demonstrates that Ugnuravik Group (defined in Fig. 6) and Kuparuk re~rvoir correlate to Okpikruak and Kongakut Formations. Whereas source of Ugnuravik Group was from the north, its correlatives were derived predominantly from the south. bik Creek which flows into Harrison Bay west of thc Kuparuk field (Fig. 3). The Kalubik Formation is the cor- relative of the lower part of the unnamed shale of Early Cretaceous age depicted in the stratigraphic summaries by Jones and Spears (1975) and Jamieson et al (1980), and probably the lower part of the Put River shale informally referred to by Bushnell (1981 ). The Kalubik Formation is typically 200 to 300 ft (61 to 91 m) thick in the Colville-Prudhoe basin. It consists of brownish-gray to black, carbonaceous, silty mudstone with moderate fissility. The mudstones contain nodular and disseminated pyrite and are locally sideritic in distinc- tive bands. A sideritic mudstone which was cored at West Sak 4 and which occurs at 5,804 ft (1,769 m) b.r.t, in Ugnu State I is characterized by an exceptionally high gamma- ray response. It forms a good correlation marker within the Kalubik Formation (Figs. 7, 8). UGNU STATE ~'1 APl **029-2000900 KBE : 75 FT. A.M.S.L. UGNURAVlK GROUP {TYPE WELl.) GR RES AT c.2. ' . '~., ~5' ',~ a ~ ~,' ~ 5580 ~ HRZ ~i ', ,804 - CONIACIAN APTIAN/ ALBIAN BARREMIAN TO E. VALANGINIAN E. OXFORDIAN FIG. 6--Lower Cretaceous sequence penetrated in Ugnu State 1 well (API-50-029-2000900) is formally proposed as type section for newly defined Ugnuravik Group, Kalubik Formation, kuparuk Formation, and Miluveach Formation. Locations of geographic names used are shown in Figure 2. Many North Slope operators recognize ltRZ unit because of its characteristic fea- ture as a highly radioactive zone. 1020 Kuparuk Oil Field, Alaska COLVlLLE 1 REft, 4T KALUBIK CREEK GR (qEI AT UGNU STATE 1 (TYPE WELL) WEST SAK cm RES AT N. KUPARUK ST. HRZ UNIT KAL. UBIK FORMATION KUPARUK FORMATION COLVILLE HIGH Iii fill YIR?ICAL (NOT TO tCALI #OII2'O#TALLY) LOCATION I~Ap MILUVEACH FORMATION PRUDHOE HIGH 1~II00411NMITLy NIDOIIIN/dJ'TLV MUIITQNI NTgfPlCl0~fl NUflIVONI PIIDOIIINAI4TLy FIG. 7--West to east correlation of logs and interpretive lithologies of Ugnuravik Group in five wells across Colville-Prudhoe basin shows thinning onto Colville and Prudhoe highs and presence of unconformities al several stratigraphic levels. Ugnuravik Group is more than 1,500 ft (457 m) thick in axis of Colviile-Prudhoe basin (see also Fig. 2). The top of the Kalubik Formation is picked on wireline logs at the sharp base of the overlying HRZ unit where the gamma-ray curve falls consistently below 150 API units. A Barremian to Aptian age is suggested for this forma- tion on the basis of dinoflagellate and agglutinating fora- miniferai assemblages. The Kalubik Formation is considered to have a marine origin. Kuparuk Formation.--The stratigraphic sequence between 5,890 and 6,262 ft (1,795 and 1,909 m) b.r.t, in the Ugnuravik type section (Ugnu State 1) is formally pro- SOUTHWEST WEST SAK 15 WEST SAK 14 WEST SAK 9 GR RES AT GR RES AT GR RES AT DATUM LOCATION MAP 0 Legend I I PREDOMINANTLY 50 i I SANDSTONE SIDERmO 1OO SANDSTONE SlLTSTONE 150 feet + ~--~-~ii ~ PREDOMINANTLY VERTICAL SCALE + "'" j MUDSTONE (NOT TO SCALE HOIilZONTALLY) UGNU 1 GR RE~, AT WEST SAK 17 OR RES AT DATUM IS HIGH GAMMA MARl(ER ¥/TTHIN THE UPPER KALUBIK FORllU~TION NORTHEAST Z 3: Z 0 0 FIG. 8--Kuparuk Formation is informally subdivided into lower and upper members, each with 2 units as illustrated in this northeast to southwest section. A and B units are trun- cated by local unconformity at base of C unit in southern and western parts of Kuparuk field. Progressive onlap and overstep of C unit toward the west resulted in deposition of C unit sandstone to ~he southwest coeval with mudstone of D unit to the northe~t. 1022 Kuparuk Oil Field, Alaska posed as the type section for this lithostratigraphic unit which is here referred to as the Kuparuk Formation. It is named after the Kuparuk River which flows north into Gwydwr Bay (Fig. 3). Kuparuk is an Eskimo name whose translation is believed to be "big river" (Orth, 1971). The Kuparuk Formation is the correlative of part or all of the Kongakut Formation to the east (Detterman et al, 1975) and part or all of the Okpikruak Formation to the south and west (Fig. 5). However, whereas these latter two for- mations appear to have had a southern Brookian source, the Kuparuk Formation had a northern, Barrovian source. The Kuparuk Formation is also a correlative of the Lower Cretaceous Put River Sandstone which is present over part of the Prudhoe Bay field (Jamieson et al, 1980; Bushnell, 1981). The hydrocarbon reserves of the Kuparuk oil field occur within the Kuparuk Formation. The correlative sequence in the Mobil North Kuparuk I well, 6,774 to 7,054 ft (2,065 to 2,150 m) b.r.t, was informally named the Kuparuk River sands by the North Slope Stratigraphic Committee of the Alaska Geological Society (1970-1971). The Kuparuk River sandstone was referenced by Mor- gridge and Smith (1972), Detterman et al (1975), and Carter et al (1977). Jones and Speers (1975) referred to the same interval as the Kuparuk sandstone formation in a general stratigraphic context, and Jamieson et al (1980) described it using the section in the Arco West Sak I well as a reference. The Kuparuk Formation consists of a cyclic sequence of coarse- and fine-grained terrigenous clastic sediments and is informally subdivided into two members. Each member is further divided into two lithostratigraphic units which we informally refer to as the A unit and the B unit in the lower member and the C and D units in the upper member. These units of the Kuparuk Formation are defined on wireline logs and are also distinctive in cores. They are illustrated in the type section (Fig. 6) and a correlation sec- tion (Fig. 8). The lower member consists of a heterolithic sequence of thin to very thinly interbedded sandstones, siltstones, and mudstones. The sediments within the lower member form a continuum in terms of their sandstone (plus siltstone) to mudstone ratio and sedimentary features and they are more fully described under the section headed "Reservoir Description." The upper member is characterized by massive sand- stones and siltstones (in the C unit) and silty mudstone (in the D unit, Fig. 8). The distribution of the D unit is restricted to the northeastern part of the field (Fig. 10), and in its absence the C unit is overlain by the Kalubik For- mation. The boundary between the Kuparuk and Kalubik Formations has been cored in four wells and is considered to be a gradual change in lithologies. A distinctive feature of the upper member is the occurrence of abundant glau- conite grains within both of the units and the common occurrence of siderite-cemented bands within the sand- stone of the C unit. The petrologic characteristics are described further under the section headed "Reservoir Description." The upper member is locally unconformable on the lower member. This is evident from the progressive loss of section within the lower member (A and B units) west and south of the field (Fig. 8). The distinct characters of the upper and lower members are further suggested by the dif- ferences in their fossil assemblages. Where dinoflagellates have been recovered from the upper member, they have shown a much greater abundance and diversity than those from the lower member and are indicative of a Hauteri- vian to Barremian age. The sparse dinoflagellate assem- blages from the lower member are similar to those from the underlying formation and are thought to be diagnostic of a Valanginian to Barremian age. The break between the upper and lower members is also reflected in changes in the composition of the agglutinating Foraminifera and miospore assemblages. The above datings broadly agree with the reportings of Tabbert and Bennet (1976), who determined a Neocomian age from 34 species of' microplankton. Bergquist (1966) and Detterman et al (1975, p. 25) recognized the presence of a Jurassic to Cretaceous transition zone, and this may have led to some misleading reports of a Jurassic age for the Kuparuk Formation (Morgridge and Smith, 1972; Bushnell, 1981). On the basis of the microfauna and the presence of bio- turbation, glauconite, and sedimentary structures, the Kuparuk Formation is thought to have been deposited in a shallow marine environment. Miluveach Formation.raThe stratigraphic sequence between 6,262 and 6,793 ft (1,909 and 2,070 m) b.r.t, in the Ugnuravik Group type section (Ugnu State 1) is formally proposed as the type section for this new unit. The new unit is here named the Miluveach Formation. It is named after the Miluveach River which is located west of the Kuparuk field (Fig. 3). The Miluveach Formation is a cor- relative of the lower part of the Kongakut Formation which crops out along the flanks of Bathtub Ridge to the southeast (Detterman et al, 1975), and on tenuous age relationships is possibly a correlative of the Pebble Shale to the west. The Miluveach Formation is typically 300 to 500 ft (91 to 152 m) thick in the Colville-Prudhoe basin. It consists of grayish-brown to black silty mudstone. The mudstones are micaceous and contain finely disseminated pyrite, pyritized foraminifera, and rounded quartz grains. Sideritic mudstones are rare, which distinguishes this unit from the Kalubik Formation. The mudstones are poorly fissile and brittle with a blocky fracture in cored samples. Thin siltstones and very fine-grained sandstones near the top are interpreted to herald the deposition of the overly- ing Kuparuk Formation. Although the upper sedimento- logic boundary of the Miluveach Formation is gradational, it is frequently characterized by a sharp break in the sonic log (Fig. 8). Kingak Shale Formation The Kingak Shale Formation underlies the Ugnuravik Group in the Colville-Prudhoe basin (Fig. 4). The type sec- tion was named and described by Leffingwell (1919), while Detterman et al (1975) described additional reference sec- tions. The Kingak Shale Formation in the Colville- Prudhoe basin is essentially the same as described at the George J. Carman and Peter Hardwick 1023 II/ SAK G Legend APPROX. [~ FtELD SOUTHWEST 1.0 W $~1< 20 ~800 ~ PINGIf-OUT/IRUNCATION ~ OIL-WATER-CONTACT ,~ DISCOVERY W E k L MilII KUPARUK FIELD Ii DOWNFLANK STRUCTURE I NORTHEAST 1.0 i IIi 1.2 1.4 1.4 '" I.' ,' 11! 1.6 18 t';~ k ~.r .. 2 I 4 ,i- i" ~ iI il, , 'qlllr i . ,,I |'t; !,.;!' 2.o FIG. 9--Structure at top of Kuparuk reservoir is best defined by a strong seismic reflector at approximately 1.3 to 1.5 sec two-way time on seismic line illustrated. Structure map of this horizon shows northwest to southeast-trending anticline with two groups of faults on northeastern flank. Outline of Kuparuk field is, however, defined by stratigraphic pinch-out and truncation to the west and south and along the line of an oil-water contact to the easl and north. I O24 Kuparuk Oil Field, Alaska type section, namely a dark gray brown, marine mudstone with numerous siltstone and silty mudstone horizons. Source rock studies have suggested the total organic car- bon content of these rocks is about 3% by weight in the Prudhoe area (Seifert et al, 1979). Whereas the Kingak is as young as early Tithonian and Kimmeridgian age in northeastern Alaska (Detterman et al, 1975), the youngest Kingak determined to date in the Colville-Prudhoe basin is of early Oxfordian age. This apparent absence of late Oxfordian to Berriasian strata represents an hiatus of approximately 20 m.y. and is though to represent a significant stage in the tectonic development of this part of the north Alaskan continental margin. STRUCTURE The structure of the Kuparuk oil field is best defined by a seismic reflection at approximately 1.4 to 1.6 sec two-way . time (Fig. 9). The reflection is generated from a change in acoustic and density properties at the top of the Kuparuk Formation and is associated with a marked sonic break on subsurface open-hole logs (Fig. 7). A structure depth map on this horizon (Fig. 9) demonstrates a broad antiform with a crest at about 5,600 ft (1,707 m) subsea and with flanks continuing below 7,000 ft (2,134 m) subsea. The structure has a prominent northwest to southeast axial trend which plunges gently to the southeast. The north- eastern flank is severely disrupted by a series of faults trending northwest which is approximately parallel with the Barrow arch. These are augmented by a subordinate north-south group of faults (Fig. 9). The faults have throws up to 200 ft (61 m), but are more generally in the range of 50 to 11210 ft (15 to 31 m) with the downthrown blocks predominantly to the east. Minor faults down- thrown to the west and southwest occur within the field area, whereas larger faults with western downthrow are believed to provide a trapping mechanism to smaller, sepa- rate hydrocarbon accumulations downflank to the east and northeast (Fig. 9). The majority of the faults extend upward only as far as the HRZ unit, indicating that they are no younger than Early Cretaceous. The trapping mechanism of the Kuparuk pool has both structural and stratigraphic components. Stratigraphic pinch-out of the C unit and truncation of the A unit reser- voirs limit the pool to the south and west (Fig. 8). Struc- tural dip closure exists to the north and east. An oil-water contact has not been observed within a single, clean reser- voir lithology because of thin beds. However, the contact has been determined to exist between approximately -6,530 ft (-1,990 m) in the south, and at least -6,700 ft (- 2,042 m) in the north. Furthermore, observations of oil and water levels in 15 wells in the eastern field area suggest that this oil-water contact has a uniform tilt of about 0.5° toward the north-northeast. However, the possibility of a step-faulted contact cannot be discounted without addi- tional data. The tilt is thought to have resulted from the inability of the reservoir fluids to equilibrate during the Tertiary to present-day northeastward tilting of the Alaska Arctic plain. The Kuparuk pool is mapped over 300 mi2 (777 km2) with a vertical closure of about 1,100 ft (335 m). The seal to the trap is provided by the silty mud- stones of the overlying Kuparuk D unit and, in their absence, by the marine mudstones of the Kalubik Forma- tion. RESERVOIR DESCRIPTION The reservoir quality sandstones of the Kuparuk Forma- tion in the Kuparuk oil field occur chiefly within the C unit of the upper member and the A unit of the lower member (Fig. 10). Although oil-stained sandstones are present ia the intervening B unit, they are normally thin and encap- sulated by mudstones and siltstones making economic production unlikely. The silty, dark-brown to black mud- stones of the D unit are not considered to contain any res- ervoir zones. The A unit consists of a heterolithic sequence of sand- stones, siltstoncs, and mudstones in a series of regressive cycles, each up to 70 ft (21 m) thick. Within each cycle, individual bed thickness ranges from a few inches up to 3 ft (0.9 m), but the sandstones are commonly amalgamated into bodies of up to 40 ft (12 m) thick. The sandstones are buff to dark brown (light gray when not oil stained), fine to very fine-grained, quartzose arenites with well-sorted subangular grains. The sandstones exhibit ripple cross- laminations and low-angle cross-laminations. Thc mud- stones within the A unit are dark gray-brown and silty. X-ray diffraction analysis of thc sparse (less than 5% volume) intergranular clays indicates they are predomi- nantly kaolinite and illite. Biogenic reworking has intro- duced higher percentages of clays into some of the finer grained elastics. These clays, together with secondary quartz overgrowths, provide the principal cementing and porosity-reducing agent. Rare siderite-cemented bands occur in localized areas within the A unit (see West Sak 12, in Fig. 10), and are recognized by fast interval transit times, high resistivities, and high bulk densities. The A unit is correlated and mapped over the entire pool area and isopachs of the unit define an axis of maximum thickness of approximately 120 ft (36 m) striking northeast to southwest (Fig. 11). The unit thins dramatically to the west where it is truncated by a local intraformational unconformity at the base of the C unit (e.g., West Sak 18, Fig. 10). At least four divisions (dashed lines in Fig. 10) are discernible in the A unit from wireline logs; these have been substantiated by a sedimentologic analysis of cores, and they define depositional cycles whose sediments have coarsening-upward grain-size profiles. Mapping of the individual cycles (not shown) has defined lensoid bodies approximately 10 mi (16 km) wide, 25 mi (40 km) or more long, and 40 to 70 ft (12 to 21 m) thick. Isopachs of these bodies exhibit a strike trend similar to that of the gross A unit isopachs (Fig. 11) which, despite inconclusive dip- meter evidence, together with the regional setting suggests the provenance was probably in the northeast or east. The porosity and permeability of the reservoir sandstones of the A unit have been determined from 184 core. plug sam- ples from 11 wells. The arithmetic mean porosity is 23% and the mean horizontal permeability is 81 md. The cumu- lative pay-quality sandstones of the A unit range up to 30 ft (9 m) thick and are thought to contain approximately 60% of the field's oil in place. WEST WEST SAK 18 OR RES AT DATUM :lc LOCATION MAP Wl-l~ ~ llli, WEST SAK 11 GR RES ,I,T WEST SAK 9 GR RES AT SANDSTONE FORMATION Legend PREDOMINANTLY O SANDSTONE SANOSTONE 100 PREDOMINANTLY SILTSTONE 150 feet PREDOMINANTLY VERTICAL. SCALE MUDSTONE (NOT TO SCALE HORIZONTALLY) WEST SAK 12 Gfl RES AT DATUM IS HIGH GAMMA MARKER WITHIN THE UPPER KALUBJK FORMATION WEST SAK 1 GR RES AT EAST FIG. 10--Lower member A unit and upper member C unit of Kuparuk Formation contain principal reservoir zones of Kuparuk field. Correlation of regressive deposi(ional cycles within these units displays truncation in western part of field in lower member and onlap and overstep in upper member. 1026 Kuparuk Oil Field, Alaska The lithologies of the B unit are very similar to those of the A unit. There is, however, significantly less sandstone. which is reflected in the average bed thickness which ranges up to 2 in. (5 em) for the sandstones and from 2 to 4 in. (5 to 10 cra) for the mudstones. Internal sedimentary structures, such as load structures, together with graded beds and a "flaser and linsen" structure characterize the B unit. Toward the top of the unit, these sedimentary struc- tures are frequently obscured by varying degrees of biotur- bation. The B unit is characterized by an upward-coarsening sedimentary trend which is evident in the wireline-log responses (Figs. 8, 10). This feature permits a fieldwide correlation which demonstrates thinning of the unit by truncation in the western pool area (e.g., the thinned B unit in West Sak 11, Fig. 10). The B unit is more than 150 ft. (46 m) thick (Fig. 11). The prevalent sedimentary and bio- genie structures, together with a rich occurrence of land- derived miospores, suggest a shallow marine environment of deposition. The C unit of the Kuparuk upper member consists of sandstones and siltstones with intergranular clay. The sandstones are buff to gray brown (greenish gray when not oil stained) and contain medium to fine, occasionally coarse-grained quartz with locally abundant granular glauconite. The glauconite commonly comprises over 25% by volume of the granular content. The sand grains are poorly sorted and subangular. In the western areas, they constitute a pebble conglomerate at the base of the unit. In cores, the sediments of the C unit display well- defined upward-coarsening grain-size profiles in two dis- tinct regressive cycles. The dashed lines in Figure 10 demonstrate these cycles, with the upper cycle being fur- ther divided to highlight the reservoir interval near the top of the C unit. lntergranular clay is present in quantities of approxi- mately 3% by volume in the reservoir sandstones and up to 15°'/0 in the finer grained elastics. The clays have been determined by X-ray diffractometry and scanning elec- tron microscopy to be detrital illite/smectite, authigenic kaolinite, and mixed layer illite/montmorillonite. These detrital clays are believed to have been dispersed through- out the C unit sandstones and siltstones by strong biotur- bation. Matrix cementation in the upper member is not so marked as in the lower member and quartz overgrowths are rare. The C unit is characterized by bands of siderite- cemented sandstones which contain negligible quantities of intergranular hydrocarbons. They are up to 8 ft (2.5 m) thick and in places form a correlatable zone over 10 to 20 mi2 (26 to 52 km2), particularly in the sandstones in the eastern pool area (see West Sak I and 12, Fig. 10). Within the field area, the isopachs of the C unit define a distinct lobe-like geometry striking northeast to south- west. The maximum thickness is about 150 fi (46 m) on the eastern flank (Fig. 11). Jamieson et al's (1980) regional correlations suggest this trend persists farther east (their Fig. 19). Correlation of the two regressive sequences within the C unit suggests progressive onlap with overstep toward the west. During late C unit deposition, the sand- stone extended as far west as the West Sak 15 well and was probably deposited coevally with part of the D unit (Fig. ISOPACHS OF THE KUPARUK FORMATION o $ MILES FIG. 1 I--lsopachs (in feet) of Kuparuk Formation and of four informal Kuparuk units show a common thickening trend toward the northeast. Lower member A and B units thin abruptly at zone of truncation in the west. Distribution of C and D units is restricted to the north and east. 8). Mapping of the C unit demonstrates that the better res- ervoir sandstones are restricted to about 80 mC (207 km2) in the east-central part of the pool area. The porosity and permeability of the reservoir sandstones in the C unit have been determined from 260 core plug samples from nine wells. The arithmetic mean porosity and permeability are 21% and 90 md, respectively. Permeability, however, ranges from less than 1 to over 1,350 md reflecting great variability. The cumulative pay-quality sandstones of the C unit range up to 60 ft (18 m) in thickness and are thought to contain approximately 40% of the field's oil in place. OIL COMPOSITION The composition of crude from the Kuparuk Formation in the well N.W. Eileen State I has been previously described by Magoon and Claypool (1981). The general characteristics of this oil, which is believed to be in a sepa- rate accumulation downflank of the Kuparuk field, was also briefly described by Jones and Speers (1975). Magoon and Claypool (1981) classified this oil as one of their Barrow-Prudhoe types which are generally medium gravity, high sulfur (greater than 0.6%) oils and are char- acterized by pristane to phytane ratios typically less than 1.5 and/¢'~C and ~i'~4S in the ranges of-30.3 to -29.8 ppt and -3.0 to + 2.1 ppt, respectively. Independent results by BP and Sohio research laborato- ries in Sunbury, England, and Warrensville, Ohio, con- firm Magoon and Claypool's conclusion that the oils from George J. Carman and Peter Hardwick 1027 ISOPACHS OF THE KUPARUK FM. A UNIT o 5 MILES '"' rs i ISOPACHS OF THE KUPARUK FM. B UNIT o ISOPACHS OF THE KUPARUK FM. D UNIT FIG. 11--Continued the Prudhoe Bay field, the Kuparuk field, and the overly- ing Upper Cretaceous sands are of the same genetic origin. Saturate alkane chromatograms of the Kuparuk oils have shown them to be highly paraffinic with occasionally Iow naphthenic makeup, suggesting perhaps that some prefer- ential biodegradation has occurred. The sulfur content ranges from about 1.4 to 2.0% by weight. The gravity of the Kuparuk crude ranges from about 15 to 26° APl and appears to be related to its structural elevation above a tilted oil-water contact (Fig. 12). The average gravity of the Kuparuk field crude is about 24°API at 609E Figure 13 summarizes geochemical analyses of some oils in the Kuparuk and Prudhoe area and demonstrates some of the similarities of these Barrow-Prudhoe types. The Prudhoe Bay Permo-Triassic reservoir contains 27° (aver- age) oil and has a large gas cap; the same reservoir in the 1028 Kuparuk Oil Field, Alaska 8001 ?OO! $OOi 500- ,' .., 3OO O -' .......... ~ .............. ~.~-.- 14 $ 6 18 2'0 22 24 26 28 CRUDE GRAVITY: *APl FIG. 12--Plot of Kuparuk crude gravity versus sample height above oil-water contact demonstrates trend toward heavier oils (15 to 20° APl) close to water level. Average gravily is 24° APl at 60°F. western Prudhoe (Eilecn) area has a similar API oil' and a smaller, separate gas cap. The Early Cretaceous Kuparuk reservoir contains an average 24°API oil and no observed gas cap. It has a higher sulfur and asphaltene content and lower concentrates of light end material than at Prudhoe. The Upper Cretaceous sands contain I I to 26° APl oils (Petroleum Information, 1982) which have an even higher sulfur content. Despite these subtle variations in proper- ties, however, it is thought that these crudes are genetically related, sharing perhaps a common source type or co- source. Morgridgc and Smith (1972) attributed thc Prudhoe Bay oils to a Lower Cretaceous (HRZ) origin, and it is difficult to refute the ubiquitous close association of the HRZ unit and the known hydrocarbon accumulations on the North Slope. However, these Lower Cretaceous mudstones have been buried to only about 6,000 ft (1,829 m) in the Colville-Prudhoe trough and about 7,500 ft (2,285 m) at Prudhoe, and are thought to be immature. Using biologi- cal marker chemistry, Seifert et al (1979) concluded that the co-sources of the Prudhoe-Kuparuk crudes were the Lower sequence Shublik Formation (Triassic), Kingak Formation (Jurassic), and deeply buried HRZ mudstones (Early Cretaceous). Migration of oil into the Prudhoe structure could not have occurred before the subcropping Permo-Triassic res- ervoirs were overstepped and sealed by the Aptian-Aibian HRZ unit. Jones and Speers (1975) reported that. the dis- tributiml of residual oil in cores from below the Prudhoe field oil-water level indicated that primary migration filled tile st ruct ure to tile spill point before the regional Late Cre- taceous and Tertiary northeastward tilting occurred. Fur- thermorc, by reconstructing paleostructural surfaces, they deduced that the neighboring, now structurally deeper, Eileen structure filled by spillage (secondary migration) from the Prudhoe structure after early Tertiary time. Fig- utc 13 demonstrates our interpretation of these migration pathways. Hydrocarbons which originated in the Lower sequence are thought to have migrated first into the Prudhoe struc- ture and filled it completely (Fig. 13). Progradation of the Upper Cretaceous and Tertiary depocenters then induced regional tilting toward the northeast, and this caused a sig- nificant redistribution of the Prudhoe hydrocarbons. By this mechanism, a classic example of an oil "plumbing sys- tem'' with spillage and leakage to successively shallower levels was created in the Prudhoe-Colville area. The mech- anism of secondary migration is not understood but may have occurred via lag deposits associated with local and regional unconformities within the Lower Cretaceous sequence (Seifert et al, 1979), and possibly along major fault systems such as those occurring along the northeast- ern flank of the Kuparuk field and bounding the western end of the Prudhoe field. This same fault system may also have provided a fairway into the overlying Upper Creta- ceous reservoirs which appear to be sealed by the perma- frost. (Jamieson et al, 1980). TECTONIC SETTING The tectonic style of development of the north Alaskan continental margin is considered to be of the passive, Atlantic type (Grantz et al, 1981), and along this margin are three distinct geologic and physiographic sectors (Grantz et al, 1979). From west to east, these are the Chuk- chi, the Barrow, and the Barter Island sectors (Fig. 2). The Kuparuk reservoir and the Barrovian sequence described herein are located within the Barrow sector. Following uplift and then denudation of the northern Ellesmerian source on the Barrow sector (as evidenced by Permo- Triassic elastic sedimentation succeeded by argillaceous deposition during Jurassic time), the provenance was effectively removed by puIl-apar! tectonics and/or regional subsidence. These events commenced about 120 to 140 m.y. ago in the Barrow sector and are probably associated with development of the Canada basin (Grantz and Kirschner, 1976; Lathram, 1976; Grantz et al, 1979; Jones, 1980; Grantz and May, 1981). Within the Barrow sector, the Barrow arch is thought to be a partial remnant of the northern landmass which continued to be a local sediment source during the late stages of tectonism. Seis- mic and well data indicate the Barrow arch was finally overstepped and buried 80 to 90 m.y. ago by Upper Creta- ceous sediments which prograded from the south. This sequence of events, occurring within a 50 to 60 m.y. per- iod, is considered a good example of the rift and drift model for the development of passive continental margins as described by Falvey (1974) and Falvey and Mutter (1981). George,J. Carman and Peter Hardwick 1029 "KUPARUK FIELD,-~---PRUDHOE BAY FIEI-D WES 7' EA S T '"%,i l. iebu~ ................ (~~ MIGRATION PATH ~ OIL [~ GAS , ,,, A B C D E ,,,, ,, ,,,,,, Small Cap In GAS CAP No No -P-T Yes Yes APl 17o to 260 24o ~ 21 9e 25'4° 25'1° · (Field average is 27°) ~34S - -2.15 :2 -1.91 -2.57 -2.70 ~ 13 C - -30.2 r~ -30.32 -29.89 -29.83 Pr/Ph ~1.5 ~1.5 = 0.8 1.0 1.2 --. CPI c. 1 c. 1.0-1.5 ~ 0.94 0.97 0.97 BJodegrad, Yes ? Slightly ~ Slightly No No FIG. 13--Geochemical analyses of crudes from several accumulations in Kuparuk and Prudhoe area suggest they are all of same genetic origin (Seifert et al, 1979; Magoon and Claypool, 1981). it is possible that (I) primary migrated hydrocarbons accumulated in Prudhoe structure (D and lB) before Cretaceous and Tertiary tilting induced (2) secondary migration/overspilling into western (Eileen) portion of Prudhoe structure (C) and further migration (3 and 4) into overlying Kuparuk (B) and Upper Cretaceous (A) reser- voirs. Analyses from locations C, D, and E are Magoon and Claypool's (1981) results from the wells N.W. Eileen State 1 (Kuparuk), Sag River State 1 (Sadlerochit), and Prudhoe Bay State 1 (Lisburne), respectively. Data given for locations A and B are summarized partly from proprietary sources. For further analytical comparisons see Table IV in Seiferl et al (1979). 1030 Kuparuk Oil Field, Alaska CANADA BARROW PRUDHOE COLVlLLE FOOTHILLS BASIN ARCH HIGH TROUGH UPPER SLOPE LOWER SLOPE ~OCEANIC ~ qRUST, INFRARIFT + + + + + MANTLE ECONOMIC BASEMENT BARROVIAN SEQUENCE FIG. 14--Barrovian sequence, containing Lower Cretaceous Kuparuk reservoir, is interpreted to be an infrarift sequence on an Atlantic-type continental margin. Similar sequences may present further exploration plays in Alaskan Arctic area, particularly on flanks of Barrow arch and local highs similar to Prudhoe structure. This model involves three evolutionary stages in the development of a passive margin (Fig. 14): rift onset phase, infrarift phase, and breakup phase. During the rift onset phase, approximately 50 m.y. prior to continental breakup, crustal doming occurs about the incipient rift. Uplift is attributed to thermal activity in the upper mantle and consequently a temperature anomaly is initiated in the lithosphere. In the Kuparuk area, a rift onset or rift phase unconformity is considered to exist at the base of the Ugnuravik Group. During the infrarift phase, a continued increase in the thermal gradient produces axial metamorphism in the deep crust which ultimately leads to collapse of a central graben block. Rapid depositional rates in continental, fluvial-deltaic, and marginal marine environments are common, as are minor angular unconformities. The Ugnuravik Group and the Kuparuk reservoir are consid- ered to be infrarift sediments deposited during the early stages of development of the continental margin. During a 5 to 10 m.y. period prior to the breakup phase, the intensity of relative uplift and subsidence increases. A breakup unconformity marks the onset of subsidence and heralds a major marine transgression which is followed by a subsidence-induced migration of depocenters in the overlying progradational wedge. The hiatus at the top of the Ugnuravik Group is interpreted to be the breakup unconformity in the Colville-Prudhoe basin. The tectonic development of the north Alaska continen- tal margin in this style, and the resulting switch of prove- nance and widespread unconformity during Early Cretaceous time is of major significance for oil explora- tion (Rickwood, 1970; Morgridge and Smith, 1972; Jones and Speers, 1975; Bushnell, 1981). The Ellesmerian (Lower) sequence contains reservoirs which are truncated by a rift-phase unconformity and overstepped by post-rift Brookian shales that form an effective hydrocarbon seal. The infrari ft sediments (Fig. ! 4) of the Barrovian sequence include the reservoir sandstone of the Kuparuk field and the Put River sandstone over the Prudhoe field. After breakup, the depocenter of Cretaceous sediments moved progressively northeastward across the area and eventu- ally, by Tertiary time, the depocenter had moved offshore the present coastline. This progradation resulted in regional northeast tilting with important effects on the redistribution of hydrocarbons. Falvey (1974) also sug- gested that the period of greatest heat flow on a develop- ing Atlantic margin occurs during the breakup phase which, in the Barrow sector, appears to have been during George J. Carman and Peter Hardwick 1031 late Albian time. Such a thermal event may have contrib- ( kantz. A.. and C. E. Kirschner, 1976, Tectonic framework of petrolifer- uted to the maturation of source rocks in thc Kuparuk- Prudhoe area. DEVELOPMENT PLAN The proposed development area of the Kuparuk field is approximately 200 mi2 (518 km2), and the cumulative pro- ductive interval is at least 90 ft (27 m) thick. The current estimate of movable oil-in-place within this area is 4.4 bil- lion stock tank bbl (s,t.b.). Reservoir simulations per- formed by BPAE and Sohio suggest that the potential waterflood reserves are 1.0 to 1.5 billion s.t.b. (Clutter- buck and Dance, 1982), which makes Kuparuk one of the largest oil fields in the United States. The field will probably be developed from three central production facilities. Each facility will supply oil from 40 to 50 drill pads into a gathering system that is targeted to flow 250,000 bbl/day into the Trans-Alaska Pipeline sys- tem (Fig. 1). Approximately 700 to 900 wells will ulti- mately be drilled as it is thought that at least a 320-acre (129 ha.) well spacing will be required for efficient devel- opment of this field (Clutterbuck and Dance, 1982). It is believed that a peak production of 250,000 bbl/day may be maintained over a period of approximately 6 to 8 years after which it will decline to about 100,000 bbl/day by the year 2000. REFERENCES CITED Alaska Geological Society, North Slope Stratigraphic Committee, 1970- 1971, West to east stratigraphic correlation section, Point Barrow to Ignek Valley, Arctic North Slope, Alaska. Bergquist, H. R., 1966, Micropaleontology of the Mesozoic rocks of northern Alaska: U.S. Geological Survey Professional Paper 302-D, p. 93-227. Bushnell, H., 1981, Unconformities--key to North Slope oil: Oil and Gas Journal, January 12, p. 114-118. Carter, R. D., C. G. Mull, K. J. Bird, and R. B. Powers, 1977, The petro- leum geology and hydrocarbon potential of Naval Petroleum Reserve No. 4 North Slope, Alaska: U.S. Geological Survey Open File Report 77-475, 62 p. Clutterbuck, E R., and S. E. Dance, 1982, The use of simulation in decision-making for the Kuparuk field: Society of Petroleum Engi- neers California Regional Meeting, San Francisco, March 24-26, SPE 10762, p. 473478. Detterman, R. L., H. N. Relier, W. P. Brosg6, andJ. T. Dutro, 1975, Post Carboniferous stratigraphy, northeastern Alaska: U.S. Geological Survey Professional Paper 886, 46 p. Falvey, D. A., 1974, The development of continental margins in plate tec- tonics theory: APEA Journal, v. 14, p. 95-106. -- and J. C. Mutter, 1981, Regional platetectonicsand the evolution of Australia's passive continental margins: Australia Bureau of Min- eral Resources Geology and Geophysics Journal, v. 6, p. 1-29. pus rocks in Alaska, in Circum-Pacific Energy and Mineral Resources: AAPG Memoir 25, p. 291-307. .... and S. I). May. 198 I, Origin of the Canada basin as inferred from seismic geology of offshore northern Alaska (nbs.): Alaska Geologi- cal Society Mini-Symposium on The Origin of the Arctic Ocean (Can- ada Basin). .... S. Eittreim, and D. A. Dialer, 1979, Geology and tectonic devel- opment of the continental margin noah of Alaska: Tectonopbysics, v. 59, p. 263-291. -- and O. T. Whitney, 1981, Geology and physiography of the continental margin north of Alaska and implications for the ori- gin of the Canada basin, in A.E.M. Nairn, ed., The Arctic Ocean (The ocean basins and margins, v. 5): New York, Plenum Press, p. 439-492. Jamieson, H. C., L. D. Brockett, and R. A. Mclntosh, 1980, Prudhoe Bay--a ten-year perspective, in Giant oil fields of the decade, 1968- 1978: AAPG Memoir 30, p. 289-314. Jones, H. P., and R. G. Speers, 1975, Permo-Triassic reservoirs of Prod- hoe Bay field, North Slope, Alaska, in North American oil and gas fields: AAPG Memoir 24, p. 23-50. Jones, P. B., 1980, Evidence from Canada and Alaska on plate tectonic evolution of the Arctic Ocean basin: Nature, v. 285, p. 215-217. Lathram, E. M., 1976, Tectonic framework of northern and central Alaska, in Circum-Pacific Energy and Mineral Resources: AAPG Memoir 25, p. 351-360. Leffingwell, E. de K., 1919, The Canning River region, northern Alaska: U.S. Geological Survey Professional Paper 109, 251 p. Lerand, M., 1973, Beaufort Sea, in R. G. McCrossan, ed., The future petroleum provinces of Canada--their geology and potential: Cana- dian Society of Petroleum Geologists Memoir 1, p. 315-386. Magoon, l.. B., and G. E. Claypool, 1981, Two oil ty~s on North Slope of Alaska--implications for exploration: AAPG Bulletin, v. 65, p. 644-652. Molenaar, C. M., 1981, Depositional history and seismic stratigraphy of Lower Cretaceous rocks, National Petroleum Reserve in Alaska, and adjacent areas: U.S. Geological Survey Open File Report 81-1084, 45 p. Morgridge, D. L., and W. B. Smith, Jr., 1972, Geology and discovery of Prudhoe Bay field, eastern Arctic Slope, Alaska, in Stratigraphie oil and gas fields--classification, exploration methods, and ease histo- ries: AAPG Memoir 16, p. 489-501. Orth, D..I., 1971, Dictionary of Alaska place names: U.S. Geological Survey Professional Paper 567. Petroleum Information, 1982, Alaska Report, v. 28, p. 2, 3-10-82. Rickwood, E K., 1970, The Prudhoe Bay field, in Proceedings of the geo- logical seminar on the North Slope of Alaska: AAPG, Pacific Sec- tion, p. L-I to L-I I. Seifert, W. K., J. M. Moldowan, and R. W. Jones, 1979, Application of biological marker chemistry to petroleum exploration: 10th World Petroleum Congress, v. 2, p. 425-440. Stone, D. B., 1980, The Alaskan orociine, the palaeomagnetism and the palaeo-geography of Alaska: Tectonophysics, 63, p. 63-73. Tabbert, R. L., and J. E. Bennet, 1976, Lower Cretaceous microplankton from the subsurface of northern Alaska (abs.): Geoscience and Man, v. 15, p. 146. Tourtelot, H. A., 1979, Black shale--its deposition and diagenesis: Clays and Clay Minerals, v. 27, p. 313-321. Vail, R R., R. M. Mitchum, Jr., and S. Thompson, 1977, Global cycles of sea level changes: AAPG Memoir 26, p. 83-97. #10 #9 BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 July 31, 2001 RECEIVED JUL 3 1 2001 Commissioners Alaska Oil & Gas Cons. Commission Alaska Oil and Gas Conservation Commission Anchorage 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Obp RE: Aurora Pool Rules And Area Injection Application - Second Supplement Dear Commissioners: Enclosed is a second supplemental data set to the Aurora Pool Rules and Area Injection Application with the following items: · Two exhibits I-3 and I-9 have been amended. · Three exhibits I-2, I-5 and I-6 have been provided in a large format. · Exhibit VI- 10 is a NOPF map of the Aurora and Borealis structures. Aurora is a contiguous pool separated from Borealis. · Exhibit VI-11 is a lease map with the Aurora PA and the proposed Borealis PA. · Exhibit VI-12 provides RFT pressure data from the Aurora reservoir. · Exhibit VI-13 provides RFT pressure data from the Borealis reservoir. · Exhibit VI-14 provides the range of OWC's, API gravity and pressure data for Kuparuk, Aurora and Borealis. · Exhibit VI-15 provides a structure map of the Aurora and Borealis area. · Exhibit VI-16 provides a cross section from Kuparuk through Borealis and into Aurora. · Exhibit VII-1 Sub-Surface Safety Valves The Aurora Pool is a common accumulation of oil and gas in the S-Pad region. Supplement 1 was provided in response to your request for information on the Borealis reservoir. Details are provided that described the structure, pressures, API gravities and OWC's. Exhibit VI-16 illustrates the difference in oil water contacts from Kuparuk in the west to Aurora in east. The exhibit further highlights the graben between Aurora and the Borealis reservoir. Aurora has two gas/oil contacts one interpreted at 6678' tvdss in the western part of the field and the other at 6631'tvdss in the eastern portion of the field. There is no evidence of a GOC in the Borealis reservoir. BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 Obp Please contact the authors if you have any questions or comments regarding this request. Sincerely, Gordon Pospisil GPB Satellites Manager Attachments Author Name Jim Young Ed Westergaard Bruce Weiler Gary Molinero Fred Bakun CC: Randy Frazier (BP) J. P. Johnson (PAI) Position Office Ops. Eng. 564-5754 Dev. Geologist 564-5972 Facility Eng. 564-4350 Geophysicist 564-5103 Res. Eng 564-5173 M. P. Evans (ExxonMobil) P. White (Forest Oil) EXHIBIT I-3 Amended AURORA PARTICIPATING AREA (APA) ADL 28254 ADL 28253 ADL! 385193 , 18 17 16 15 I ADL 282551 ADL 2825,6 AD[. 47448 PBU [~o~,~ndary I I 19 20I 2~ 22 23 I Expansion I Exp Area 4 Area 3 mm~,lUlUmUalmum~amammlum,lum~mu~mumamam,,m,,l,m,,,,.,/,, m~m,m~ m ; I m 30 29! 28 27 26 25 - ~ , APA -- -m AD L, 28259 I ADL 2,8258 I ' ~ " ' ~'-'"'"'~ 'Expansion Expansion T12N-R12E I Area 2 Area 1 3 34 35 3~ -- I I ..................................................................................................................................... TllN-R12E 4 3 2 1 ,ADL. ,47450 ADL 28261 ADL, :28260 ........................... Exhibit I-9 Amended: Fluid Contacts Contact Beechey Block V-200 Block Eastern Block Crest Block North of Crest Block 6678' tvdss Per 6631' tvdss Oil Filled 6631' tvdss GOC (Beechey Pt St #1) Beechey Block (S-16) S-31 Sidewall core (S-103 RST) S-24Ai RFT 6835' tvdss 6824' tvdss Per North of Crest Per North of Crest 6812' tvdss OWC (Beechey Pt St #2) (V-200) Block Block (N Kup 26-12-12) Exhibit VI-11: Aurora C4/(3B and Borealis C4A/C3B NOPF Mat) and Lease Ownerships ~'i'~-~p)~--~l~; ~'I I-' ~P~-~ AVCG 83.33 T"-B~ 38,811[ A I IA (IAMoCo8.81 AMOCO8.81 AMOCO 8.81 1,~ 10~I~!iAVCG 25.00 BPX 16.67 ~ 9_01 ] 01_29~01 ] 01.29.01 01~29-01 ~ / 0~-31-03 07-31"01 ~0~ ADL025518 ADL028231 ADL028232 ADL385201 AOL377051 ~85 '5906 ] ~ 8 ~ADL ] 32 ~ ..... L._AD~ _.-- ~.~ .... BPX 91,19 BPX 91,19 BPX 91.19 BPX 91.19 BPX 50.00 BPX 50.00 BPX 66.67 ~HEVRON 5 . AMOGO 8.81 AMOGO 8,81 AMOGO 8,81 AMOGO 8.8t PHI~K 25.00 PHI~K 25.00 PHI~K 33.33 ~ MOBIL 50.00 ~XMOB 25.00 ~ 01-31-03 01-31-03 03~31-01 03~31-01 09~30-02 09-30-02 09-30-79 50.00 18.25 17.91 BPX 113.33 FORCE 0.01 09~3~-79 ADLQ47447 PHILA~ 36.z ADL0~82~,' 9 36.49 38.82 26.~ 1.00 01-31-03 ADL385193 BIL AK PHILLIPS 33.33 %SAME ADL028~,57 %SAME 09-30-79 03-27-84 OTHERS CHEV. 0.11 03-27-84 ADL028243 BPX 39.28 UNOCAL 4.95 ADL028248 MOBIL O. O,36 CHEV. 0.11 o3-27-84 ADL025661 03-~7-84 ADL028244 01-31-03 ADL385189 EXXMOB 5000 pHILAK 50.00 03-27-84 09~0-79 03-27-84 03-27-84 i 03-27-84 %SAME 33.33 24.33 23.88 03-27-84 ADL028263-1 BPX 17.78 0.67 %SAME 0.01 09-30-79 03-27-84 ADL047451 33.33 PHILAK 36.49 24.33 41LAK 24.33 EXXMOB 35.82 23.88 EXXMOB 23,88 BPX 26.66 BPX 17.78 BPX 17.78 MOBILAK 1.00 MOBIL AK 0.67 MOBIL AK 0.67 FORCE 0.02 FORCE 0.01 FORCE 0.01 09~30-79 09-30-79 03-27~84 ADL047453 ADL047452 ADL028264 03-27-84 ADL0282~ 03-27-84 ADL0282~ Exhibit VI-12' Aurora RFT Pressures 6300 Aurora RFT Pressure Data 64OO 6500 6600 6700 6800 6900 7000 7100 & 4~ S-104 C-Sand i XVt200 C-Sand & S-24Ai C-Sand S-24Ai A-Sand [S-24Ai A-Sand Pressure~--~--~ 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 psia Exhibit VII-l: Sub-Surface Safety Valves The Aurora Pool Rules motion to the AOGCC concerning sub-surface safety valve requirements is based on modernizing Conservation Order (CO) 98A, which was generated in March of 1971. CO-98A required the installation of a Sub-Surface Safety Valve (SSSV) below the base of the permafrost. Aurora Pool Rules request that SSSV be installed only in Gas or Miscible Injectant (MI) injectors. Aurora producers are relatively low rate oil wells on artificial lift in a water flood development. SSSV's are not deemed prudent for such wells. It should be noted that BPX is not asking for a waiver of a statewide rule, our proposal will continue to exceed the requirements of the statewide rules by continuing to install and maintain surface safety valves (SSV). All wells (Producers, Water and MI injectors) will have Surface Safety Valves (SSV) installed in the tree assembly. I. The SSSV requirement was originally requested by BPX based on the low level of experience with arctic production operations. With over three decades of arctic operations, BPX has gained substantial operating experience. The earlier request by BPX in the application which generated CO-98a was based on the potential freeze back of the permafrost, by placement of the SSSV it was thought that loss of well control, due to casing collapse would be prevented. Arctic design of casing strings and cement formation has clearly demonstrated that this is no longer a concern. II. A Consequence Assessment for Aurora, based on extracts of report, Naughton, E.: "Removal of SSSV from Kuparuk River Unit Wells. Consequence Assessment." This assessment consisted of Hazard Identification, Hazard Analysis and Consequence Analysis. Subsequent to the 1994 assessment, SSSV's were removed from the majority of wells from both the Prudhoe Bay Unit (PBU) and Kuparuk River Unit (KRU) without incident. a. The Aurora Consequence Assessment showed that there is no statistical difference in the predicted frequency of uncontrolled flow for Aurora Wells with or without SSSV's, 1.8357 x 10-5/well year vs. 2.8087 x 10-5 / well year, respectively. Given the extensive historical data used in the study, a factor of 5 (half a magnitude) would be required for a difference to be deemed statistically significant. bo The frequency risk of the 1994 Risk Assessment has been updated using the frequency of uncontrolled flow at PBU. Currently PBU has 1056 oil producers, 115 with SSSV installed. Injection wells: 32 gas injectors with SSSV, 84 MI injectors with SSSV and 122 Produced water/Seawater injectors without SSSV. There is no record of a SSSV being used in Alaska to prevent uncontrolled flow to the surface from an onshore well. c. Further, the base assessment found that the frequency risk was actually higher in wells with SSSV's installed during Wireline and Workover Operations due to the increased work activity involving SSSV maintenance. Again this risk was less than the one half an order of magnitude, so it is considered statistically significant. III. Granting this request will improve the lift efficiency of operations at Aurora Field, by reducing the number of operations to service the valve and eliminate an additional restriction in the flow stream. Development cost will be reduced by not installing this equipment on the Oil Producers. This conforms with prudent oil field management and will not adversely affect ultimate recovery. IV. SSSV's provide only redundant level of protection to the SSV. The risks, which were thought to justify the extra protection provided by SSSV's, have proven to be either absent or extremely unlikely in Aurora Oil Pool wells. In addition, the requirement for subsurface safety valves may preclude or hinder the development and application of various alternate completion techniques being studied for the North Slope. #8 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: AURORA OIL POOL, PRUDHOE BAY FIELD POOL RULES AND AREA INJECTION ORDER. APPEARANCES: Commissioners: TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska July 24, 2001 9:00 o'clock a.m. MS. CAMMY OECHSLI TAYLOR, MS. JULIE HEUSSER CHAIRPERSON METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 ORIGINAL 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Witnesses: TABLE OF CONTENTS DIRECT Philip Frank Cerveny Frederick E. Bakun 26 James Patrick Young 45 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 PROCEEDINGS (On record - 9:06 a.m.) THE CHAIRPERSON: I would like to call this hearing to order. Today is July 24, 2001. We're at the AOGCC offices at 333 West Seventh, Suite 100. The time is approximately six minutes after 9:00. The subject of today's hearing is BP's application for pool rules and area injection order for the Aurora Oil Pool. At the head table here to my left is Commissioner July Heusser. My name is Cammy Taylor. And to my right is Laura Ferro from Metro Court Reporting. These proceedings are being recorded and transcribed. Transcripts can be acquired directly through Metro Court Reporting. Today's hearing was noticed for a public hearing and published in the Anchorage Daily News on June 22, 2001. The order of proceedings today, the Applicant will present testimony first. All persons wishing to testify will be sworn. If you wish to give expert testimony, we will ask that you provide your qualifications and the Commission will decide if your testimony will be accepted. Each -- any member of the audience who may have questions that they wish to have asked can submit those in writing through a Commission representative. Mr. Crandall is seated in the back of the room. He can forward your questions to the front, and if there are any persons wishing to make oral statements, they METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 can do so after all the testimony is presented. Who was going -- are you going to start this? MR. POSPISIL: I'll start this. THE CHAIRPERSON: Okay. If you would like to come up and sit up here at the table. You have microphones so that we can have you recorded. MR. POSPISIL: Swear in or ..... THE CHAIRPERSON: Are you giving testimony first? proceeding. MR. POSPISIL: I'm just going to introduce the THE CHAIRPERSON: Go ahead. MR. POSPISIL: Okay. My name is Gordon Pospisil. I'm the development manager responsible for the Aurora Oil Pool. I have worked in this role since November 1999, first with ARCO Alaska, and since July 2000, with BP Exploration Alaska. We are here today to present testimony for a combined application for pool rules and area injection operations for the Aurora Oil Pool located within the Prudhoe Bay Unit. Philip Cerveny will begin testimony with an introduction to the field geology. THE CHAIRPERSON: Okay. You can remain seated there if you would like. There's another microphone there. Would you raise your right hand? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 (Oath administered) MR. CERVENY: I do. PHILIP FRANK CERVENY having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION THE CHAIRPERSON: Would you please state your full name and who you are representing, and spell your last name so that the recorder has it on record. A My name is Philip Frank Cerveny. I'm representing BP Exploration Alaska. THE CHAIRPERSON: How do you spell your last name? A C-e-r-v- as in Victor, e-n-y. THE CHAIRPERSON: Thank you. Do you wish to be considered an expert? A Yes, I do. THE CHAIRPERSON: Would you please state your qualifications? A I'm a senior development geologist with BP Exploration Alaska. I've received a bachelor of arts and master of science degree in geology from Dartmouth College, a doctor of philosophy degree from the University of Wyoming in geology. I was employed by ARCO Exploration Production Technology starting in 1990 and METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 have worked on a variety of projects in Alaska since 1991. I've been working with the greater Prudhoe Bay Western Development Team since August of 2000. I would like to be acknowledged today as an expert witness. THE CHAIRPERSON: questions or anything? witness. A Okay. Do you have any COMMISSIONER HEUSSER: I have no questions. THE CHAIRPERSON: We'll consider you an expert I'll begin with the geologic introduction. Thank you. The Aurora Pool is located on Alaska's North Slope as illustrated Exhibit I-1. This is a map showing the North Slope, the unitized areas of the North Slope and the Aurora Pool shown by the circle here. Adjacent are the Kuparuk River units, the Prudhoe Bay units, or the North Star unit, and the Milne Point unit. North is -- north is to the top of the map, and note the scale here down to the lower right. The Aurora Pool was confirmed in 1999 by the drilling of the V-200 well. The reservoir intervals for the Aurora Pool is the Kuparuk River Formation. The Aurora Pool overlies the Prudhoe Bay Unit, PBU, Saddlerochik (ph) Group reservoirs in the vicinity of S-Pad. In addition to the V-200 well, the S-100, the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 S-101, the S-102, S-103, S-104, and S-105 wells are recent Kuparuk River Formation penetrations in this area. The North Kuparuk 26-12-12 and Beechey Point State number 1 wells both drilled in 1969 were the first wells to penetrate and test hydrocarbons in the Aurora Pool. A number of PBU Sag River Ivishak development wells also penetrate the overlying Kuparuk River Formation. The S-24 AI well confirmed the presence of oil on the east side of the north-south dividing fault. 4 S-Pad and M pad well penetrations in term well C define the southeastern limit to the Aurora accumulation. As shown on Exhibit I-2, the top of the Aurora structure crests at 6,450 true feet true vertical depth subsea, or tvdss. The deepest interpreted oil- water contact or owc is at 6,835 tvdss in the Beechey Point State number 2 well. This is a structure map of the Aurora accumulation north. Again, it's the top of the map. Scale is here down on the lower left-hand side. These squares here are miles. This map shows some of the wells I was referring to. The S-Pad wells are largely here. The Prudhoe Bay S-Pad wells. Some of the newer wells I mentioned, the S-100 through S- 105, would be generally in this area. The Beechey area, Beechey wells here. S-Pad itself is located METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 right at this spot. Exhibit I-3 shows the location of the Aurora participating area, or APA, including expansion areas identified by the Department of Natural Resources. The area encompassed by the Aurora Pool will be removed from the Prudhoe Bay Field Kuparuk River Oil Pool rules under Conservation Order 98A. This is a map of the PA area, showing the expansion area as 1, 2, 3, and 4. Again, north is the top of map. Stratigraphy. The productive interval of the Aurora Pool is the Kuparuk River Formation informally referred to as the Kuparuk Formation. This formation was deposited during the early cretaceous geologic time period between 120 and 145 million years before present. Exhibit I-4 shows a portion of the open hole wire line logs from the V-200 well. This type log illustrates the stratigraphic definition of the Aurora Pool. The log is scaled in true vertical depth subsea, and also as a measured depth track, MD. In the V-200 well, the top of the Kuparuk Formation occurs at 6,693 feet tvd subsea or 6858.5 feet measured depth, and the base occurs at 7,070 feet tvd subsea. Again, this is the type log showing the subsea tvd tract. This would be true vertical depth, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 and the measured depth as drilled in the well. The Kuparuk Formation was deposited as marine shore face and offshore sediments, and is composed of very fine to medium grained quartz-rich sandstone which is interbedded with siltstone and mudstone. The sandstones typically have higher resistivity 3 to 50 ometers than the surrounding lithologic units. The Kuparuk Formation base is bounded by its contact with the early cretaceous aged Miluveach Formation and is distinguished by a change in lithology and conventional electric log character. The Miluveach Formation is a shale with low resistivity 1 to 3 ometers. The Kuparuk Formation top is defined by its contact with the early cretaceous age Kaluvik (ph) Formation, or the early cretaceous age highly radioactive zone otherwise known as HRZ Formation. Both are shales and are distinguished from the Kuparuk River Formation by a change in lithology and conventional electric log character. Kaluvik Formation is a dark gray shale with a gamma ray log signature of 80 to 135 api units. And the HRZ is a black organic-rich shale with a gamma ray log signature typically greater than 150 gamma api units. The Kuparuk Formation in the Aurora Pool is METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 stratigraphically complex characterized by multiple unconformities, changes in thickness and sedimentary faces, and local diogenetic cementation. As shown on type log in Exhibit I-4, the Kuparuk Formation is divided into three stratigraphic intervals from oldest to youngest. Let me to -- split this exhibit in half just for size -- size purposes. The A unit shown here labeled here on the side of the log, the B from the top of the A upwards shown here on the side of the log. And back to the top of the log, the Kuparuk C interval. The A and C intervals are divided into a number of sub-intervals. The overlying unit called the D shale is locally present in the northern part of the Aurora Pool. It is not present at the V-200. The unconformities affect the product thickness and stratigraphy. The lower cretaceous unconformity, or LCU, has erosional topography. LCU is shown here on this diagram. It truncates downward and dips to the east where it successfully removes the Kuparuk B and Kuparuk A intervals. The C4 unconformity, which would be located here, truncates downward to the east progressively removing the C4A, C3B, C3A, C2, and C1 sub-intervals before merging with LCU. Young METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 uncomformity called the preaptian (ph) unconformity also affects the Aurora Pool. At the Beechey Point wells and the western portion of the Aurora Pool, the Kuparuk Formation is unaffected, and the HRZ interval above this unconformity is in contact with the Kaluvik Formation. However, this unconformity also truncates downward to the east. At the V-200 well, another S- Pad well is to the east. The KaluVik Formation is eroded, and the HRZ interval is in contact with the Kuparuk C4B sub-interval. This preaptian unconformity eventually truncates the Kuparuk C4B and the C4A locally, and merges with the C4 unconformity and the lower cretaceous unconformity at the eastern edge of the Aurora area. The Kuparuk A and B units have a distinctly different stratigraphic thickness trend than the Kuparuk C units. Though not truncated, the lower A unit maintains a nearly uniform thickness throughout the Aurora area suggesting that its deposition predates significant fault movement. In contrast, the thickness of both the faces and diogenesis of the C units are variable and have been influenced by differential erosion and variable diogenetic fluid effects. As a result of these processes, the entire Kuparuk C interval thins south and southwestward, and reservoir quality varies METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 laterally and vertically. The lower Kuparuk A interval contains two reservoir quality sub-intervals, the A4 and A5 intervals shown here, which are 30 feet and 20 feet thick respectively. In the V-200 well, these sands are wet. In structural higher portions to the east, these A sand units are expected to be oil-bearing and productive. The A5 sand appears to be higher quality reservoir than the A4 sand. The overlying Kuparuk b interval is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are up to three feet thick. In the V-200 well, wire line logs show these thin B interval sands to be wet. The uppermost unit, the Kuparuk C interval, contains the primary reservoir sands of the Aurora Pool. The thickness of this interval is variable and ranges from zero feet at the eastern, truncation to 210 feet at the Beechey Point wells in the northwestern portion of the Aurora Pool. The lithology of this upper unit is variable consisting of interbedded very fine grain to medium grain sandstone with minor amounts of muddy siltstone and sandy silty mudstone. The Kuparuk C sands are generally very quartz-rich and moderately sorted. The Kuparuk C interval is METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 11 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 intensely biocerbated (ph) contributing to the heterogeneous nature of the Kuparuk C. Kuparuk C is further subdivided into the following sub-intervals from oldest to youngest: the C1, the C2, C3A, C3B, C4A, and C4B. The C1 overlies the lower cretaceous unconformity or LCU. The Kuparuk C1 and C4B subintervals are courser grained and contain variable amounts of glauconite and diogenetic siderite. The volume and distribution of siderite and glauconite plays an important role in the reservoir quality of the Kuparuk C1 and C4B intervals. These minerals are unevenly distributed and may affect a portion of the rock volume in the C and C4B sub-intervals. Due to the increase in structural clay volume, compaction and cementation, the porosity, permeability, and productivity of these subintervals are reduced. The C1 is the coarsest grain sub-interval. It's a well medium grain sandstone with occasional course and very course grains. The C1 has a fairly uniform thickness of 14 feet to 18 feet except to the southeast where it thins due to truncation. The upper portion of the C1 sub-interval gradual -- gradatially finds upward into the C2 subinterval. The C2 subinterval is the finest grain unit of the Kuparuk C METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 12 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 interval and is considered non-reservoir. In the western portion of the Aurora Pool is dominated by silty mudstone with occasional very fine grain sand laminations and inner beds. In the eastern part of the Aurora, the C2 lithology transitions to very fine grained muddy silty sandstone indicating a lateral faces change from west to east. The C2 interval has a somewhat uniform thickness of 28 feet to 36 feet in the western part of the field. The C2 thins to the southeast and is evenly -- is eventually truncated. The C3A sub-interval is composed of coarsening upward sandstone beds inner bedded with silty mudstone. The sandstone beds range from one to two feet thick, silty very fine grain sand at the base, up to 10 feet thick fine grain sand at the top. Mudstone inner beds display lateral faces variations similar to the underlying C2 sub-interval, and that they coarsen eastward to silty very fine grain sandstone toward the truncation. The overlying C3B sub-interval is distinguished from the underlying C3A sub-interval. Sandstones amalgamate in the mudstone inner beds are not present. The C4A subinterval continues the coarsening upward trend from fine grain sandstone at the base to medium grain sandstone toward the top. Due to METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 13 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 relatively course grain size and low volume of clay matrix, the C4A subinterval has the highest net to gross and reservoir quality in the Kuparuk Formation in the Aurora Pool area. The C4A and C4A subintervals are separated by an intraformational uncomformity that marks the end of the coarsening upward trend. This uncomformity, called the C4A, C4 unconformity, is a disconformity in the western half of the accumulation. However, it truncates downward through the stratigraphic section of the eastern half of Aurora where it eventually merges with the lower cretaceous unconformity. The top portion of the C4B is a finding upward sequence into the overlying Kaluvik Formation. C4 interval thickness varies due to interaction by unconformities. The interval is thickest at the Beechey Point area where total sea floor thickness exceeds 60 feet. The interval thins southeastward and is eventually truncated. Exhibit I-2 is a structure map at the top of the Kuparuk Formation. Has a contour interval of 25 feet. The top Kuparuk structure in the Aurora area is essentially a northwest to southeast oriented ridge, which is broken up by north-south striking faults. Faults are shown here in black. General slopes dipping from two and a half to six and a half degrees METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 14 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 away from the structural crest characterize the northeast and southwest flanks of the ridge. In contrast, rotated fault blocks characterize the southern and western flanks of the ridge. A major north-south striking fault with up to 200 feet of down to the west displacement effectively bisect~ the Aurora Pool into an eastern half, which is the fault mentioned here, eastern half which contains the S-Pad Sag River Ivishak development wells, and a western half which contains the V-200 well. The V-200 well is here. The southeastern terminus of the Aurora Pool is coincident with the Prudhoe high. A large basement involves structural uplift that underlies the Prudhoe Bay Field. Prudhoe High would be approximately in this -- beginning in this area. Early cretaceous and older sediments lapped over the structural high, and were later uplifted subsequently beveled off by unconformities. Thus, this major structural high east of the Aurora accumulation is devoid of Kuparuk. The Kuparuk Formation thins southward -- west -- southeastward to a zero edge against the Prudhoe high. The original truncation is orthoginal (ph) to the northwestern orientation of the overall structural ridge. As shown on Exhibit I-5, Aurora can be divided METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 15 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 into five structurally defined areas: the Beechey Block here in the west. The westernmost area is a complexly faulted area upthrown to a major north-south fault. The Beechey Point wells were drilled in this area. The V-200 Block is a structurally stable area between the Beechey Block to the west and the north- south bisecting fault to the east. The V-200 well in the first group of horizontal development wells, S- 100, S-101, S-102, penetrate this block. The Crest Block is an intensely faulted area on the upthrown or eastern side of the north-south bisecting fault. The top of the Kuparuk horizon reaches the structural crest at 6,450 feet tvdss in the crest block. Ten S-Pad Sag River Ivishak wells have been -- have penetrated the Kuparuk Formation of this block. The north of Crest Block lies north of the Crest Block, and east to the major north-south fault. The north Kuparuk 26-12-12 and Aurora development wells S-103, S-104, and S-105 provide well control in this block. The Eastern Block includes the area east of another north-south fault system near the S8 and S2 wells. The block is less structurally complex than the Crest Block and includes the southeastern thinning METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 16 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 and truncation of the Kuparuk Reservoir. Eight S-Pads Sag Ivishak wells penetrate the Kuparuk Formation in this block. Exhibit I-6 is a northwest to southeast oriented structural cross section along the axis of the Aurora structural ridge. See Exhibit I-2 for location. This cross section illustrates the effect of the north-south oriented faulting as well as the eastern truncation of the Kuparuk reservoir by three unconformities. This is the Beechey Point well here, Beechey Point State 1, V-200, S3, S16, S14, S13. See the truncation of the Kuparuk units from approximately this area to the east where they thin to zero, and the thickening of the units to the west toward the Beechey Block where they are their thickest. Exhibit I-7 is a dip oriented seismic traverse at the same northwest to southeast location as the previous cross section. Again, see Exhibit I-2 for location. This exhibit shows the overlying and underlying stratigraphy as well as the fault complexity of the area. The Kuparuk horizon is shown here in green, this green line going across the seismic line. The Schrader Bluff which is a younger unit shown here in red, and the Sag River which is a deeper unit shown in yellow. The blue lines that cut METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 17 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 these formations are are faults. Exhibit I-8 is a strike oriented seismic traverse from southwest to northeast. Again, see Exhibit I-2 for location. It shows a cross sectional view of the structural ridge that forms the Aurora Pool and also illustrates how fault complexity varies at different stratigraphic horizons. And the Schrader Bluff shown here in the red, Kuparuk in the green, Sag River in yellow. Faults are in blue. Wells shown in this section are S-101, S-31, North Kuparuk 26-12-12. The Aurora structure lies generally in this area, and this is to show the complexity of faulting at the Aurora level is more complex than the lower Ivishak -- Sag Ivishak River level, less complex than the Schrader above. Fluid contacts. Exhibit I-9 shows the interpreted oil-water contacts, otherwise known as OWCs, and gas-oil contacts in the Aurora Pool. Based on wire line logs, OWCs have been interpreted in the North Kuparuk 26-12-12 well at 6,812 feet tvd subsea, and at 6,835 feet tvd subsea, and the Beechey Point State number 2 well. Repeat formation.tester, or RFT, pressure gradient data in the V-200 well indicate a free water level at 6,824 feet tvd subsea. These data suggest either a 23 feet range of OWC uncertainty or METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 18 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 compartmentalization of the Aurora fault blocks and a westward deepening of the OWC across the Aurora area. At present, a common GOC, or gas-oil contact for the Aurora Pool has not been identified. Based on wire line logs, core analysis saturations, and core staining, a GOC is interpreted in the S-16 well at 6,631 feet tvd subsea. Based on well tests, mud log and wire line logs, a GOC is interpreted in the Beechey Point State number 1 well at 6,678 feet tvd subsea. Sidewall core saturations and staining and RFT pressure gradient data and fluid samples from the S31 and S24A wells and the Crest Block indicate oil above the GOC depths in the S16 and Beechey Point State number 1 wells. The Crest Block appears to be gas-free. Pool limits. The trap for oil and gas in the Aurora Pool is created by a combination of structural and stratigraphic features. The accumulation is bounded to the west by several faults where the reservoir is juxtaposed against impermeable shales of the overlying Kaluvik Formation and HRZ shale. To the southwest and the north, the pool limit is defined by the down dip inner section of the top of the reservoir with the oil-water contact. To the east and southeast, the reservoir is truncated by the preaptian METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 19 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 C4, and lower cretaceous unconformities. These unconformities merge at the southeastern limit of the field. The boundary of the Aurora PA including the expansion areas is within the proposed boundary of the Aurora Pool. Exhibit 1-10 through 1-12 are net sandstone maps of the Aurora Pool with a contour interval of 10 feet. This is a net sand map of the C3 -- of the C4 and C3B units of the Kuparuk. These are the primary reservoir sands in Aurora. Contour interval here is 10 feet, and north is the top of the page. Scale on this map, these are -- are a mile, these blocks. This map shows a concentration of thickest reservoir here in the V-200s through the Beechey Block areas. Shows the truncation of the reservoir here in the southeastern part. This is Exhibit 1-11. That sand map of the C3A and C31, sands which are the secondary reservoirs, again, showing the truncation here in the southeast, and a general southwest to northeast trend, the sand accumulation, contour interval here again is 10 feet. Exhibit 1-12 is a net Kuparuk A sand map. The Kuparuk A at this point is a tertiary reservoir, and, again, showing the truncation of the A down to the southeast, and contour interval 10 feet showing METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 20 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 generally the order of 10 to -- 10 to 10 or less -- 20 or less feet through the heart of the Aurora Field. Exhibit 1-13 is a net hydrocarbon pore foot map of the Aurora Pool with a contour interval. It says in the document ten feet. The contour interval here is actually one foot. This map is -- basically, they took all the rock away. This is the oil that would be left. This is how much oil, total oil accumulation there is in the Aurora Pool. You can see the one foot contour around bounding the limits of the Aurora Pool. This concludes my testimony. THE CHAIRPERSON: Thank you. Do you have any questions? COMMISSIONER HEUSSER: Yes, I do. BY COMMISSIONER HEUSSER: Q Just starting off with a general question, will you be providing readable scales of Exhibits I-2, I-5, and 1- 6? A Yes. Q Full scale or reasonable scale? MR. POSPISIL: I'.d say as far as the size of those exhibits? UNIDENTIFIED MALE SPEAKER: (indiscernible - away from microphone) MR. BAKUN: Right now all we have is the small METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 21 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 collusion. A Q A A Okay. Mr. Cerveny? Cerveny. Cerveny. What evidence is there that demonstrates that the north-south fault is acting as a compartmentalizing fault? I heard you say that it had, what was it, 200 feet of throw? Yes, 200 feet of throw. It's -- there's a difference in the oil -- slight difference in the oil-water contact across the blocks. I heard you say slight difference. How much is that? Let's see, Beechey Block -- put it back up, yeah. Beechey Block, which is the western part across the fault, the contacts are markedly different than the Crestal Block, or the V-200 Block. That -- that large fault would occur between these two blocks. So it's based on -- is there any pressure data on either sides of those faults to suggest that? Pressure data. I think that's coming next. Okay. Testimony. Then back to your Exhibit -- where are we -- I-5, could you go over again what criteria was used to define these I blocks? So that would be the -- largely on the -- on the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 22 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 fault, faulting, potentially compartmentalized areas, we have the Kuparuk Formation is -- is notorious for creating compartmentalized blocks. It only takes a fault in the order of 50 to 100 feet to completely seal off, and that's based on some evidence we see, observations we see in other fields in the area. So we've divided a field up largely based on -- on structural features. This is a major fault. This is the one we refer to that is on the order of 200 feet or so that subdivides this block, which we mentioned as being relatively stable. In other words, it's an area of less faulting as compared to the Beechey Block which is much more intensely faulted. This is a -- also a fairly sizeable fault between the V-200 Block and the Beechey Block. So really it's -- it's it's based on structural styles, structural compartments for the most part. Q And did I hear you say that you were going to talk about pressure continuity between the various blocks here later on? MR. BAKUN: (indiscernible - away from microphone) Q You mentioned that there was oil above the gas-oil contact in what, was it the Beechey Block and the Crest Blocks, did I get that correct? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 23 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A There shouldn't be oil above the gas-oil contact. I don't think I mentioned that. MR. BAKUN: (indiscernible) crest of the block of the GOC and the Beechey Block so it's a shallow (indiscernible). Q Okay. You mentioned that -- when you were talking about fluid contacts, you suggested that either there was a range of uncertainty of the fluid contact data, or there was compartmentalization of the various fault blocks. How do you go about excuse me, what are your plans to determine what the oil-water contact is versus just labeling it as compartmentalized? A The oil-water contacts are largely -- I'd say future plans would be evaluate wells on a well by well basis. We've kind of taken a defensive position that these blocks are compartmentalized and would probably largely have varying well water contacts. That will really only be proven out by further drilling for the most part. We've calculated free water levels which is the level at which there's 100 percent water in most of the wells, and there's significant variation in the free water levels across the Aurora Field, and that's -- that's telling us that there's a good chance that got some variation in oil-water contacts. Hard oil-water contacts are very difficult to pinpoint in METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 24 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A the Kuparuk Formation. unit, which is very shalely, and you can only see a hard oil-water contact when it occurs right in your reservoir sand. Otherwise, you get these very long transition zones. Now, it was my understanding that part of today's presentation was going to be kind of a discussion about the differences between Aurora and Borealis. that going to come later? MR. POSPISIL: Supplement One. We have a supplement that the next testimony will address. We brought up some -- brought in some Borealis exhibits. COMMISSIONER HEUSSER: That's all my questions. THE CHAIRPERSON: (Witness excused) THE CHAIRPERSON: right hand? (Oath administered) MR. BAKUN: Yes. Very often they occur in the B Is Thank you. Would you like to raise your FREDERICK E. BAKUN having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 25 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 THE CHAIRPERSON: Do you wish to be -- provide expert testimony for today's hearing? A Yes, I do. THE CHAIRPERSON: Would please state your name for the record, spell your last name, and then provide us with your qualifications? A Yes. My name is Frederick E. Bakun. My last name is spelled B as in boy, -a-k-u-n as in Nancy. I am an engineer with BP Exploration Alaska, Incorporated, currently working as the reservoir engineer for the Aurora development project. I received a bachelor of science degree in chemical engineering from the University of Arizona. I joined BP in January of 1996, and have worked in Alaska on a variety of projects since 1997. I've been working with the greater Prudhoe Bay western developments team since August of 2000. I would like to be acknowledged today as an expert witness. COMMISSIONER HEUSSER: An expert witness in what area? A In reservoir engineering. COMMISSIONER HEUSSER: Reservoir engineering. THE CHAIRPERSON: And has your work since '96 been in the area of reservoir engineering? A Yes. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 26 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 THE CH3~IRPERSON: Okay. A Part of it was as a production engineer for the waterflood in Prudhoe Bay, and then the last ten months I've worked as a reservoir engineer for the western developments, and prior to that, I was the North Slope reservoir engineer for Prudhoe Bay. THE CHAIRPERSON: Do you have any additional questions? COMMISSIONER HEUSSER: No. THE CHAIRPERSON: Do you have any objection? COMMISSIONER HEUSSER: No. THE CHAIRPERSON: You may proceed. A The reservoir description for the Aurora Pool is developed from the Aurora log model. Geo Logs Multi Man (ph) is used as the porosity lithology 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 Smith's (ph) correlation is used to model water saturations. Results frOm the log model are calibrated with core data, including lithologic descriptions, x-ray to fraction, and point count data obtained from wells in the Aurora Pool and nearby Borealis reservoir. Supplemental core data was analyzed from wells in the eastern portion of the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 27 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Kuparuk River Unit, KRU. Wells with Aurora core intervals in the data set are Beechey Point State number 1, S4, and S16. Porosity and permeability. Porosity and permeability measurements were based upon routine core analysis, air permeability with Klinkenburg (ph) correction from the following well set: S16, S4, Beechey Point State number 1, Northwest Eileen 1-01, Northwest Eileen 1-02, and Northwest Eileen 2-01. The ratio of vertical to horizontal permeability, ky over kh, was 0.006 per 20 foot interval based on the harmonic average of routine core data. Typical single plug ky kh ratios ranged from 0.4 to 1.2. Exhibit 2-1 shows values for porosity and permeability by zone that were used in reservoir simulation. This exhibit shows the five layers that were used in the reservoir simulation. The corresponding zone as Kip described in the previous testimony along with porosities ranging from approximately 16 to 25 in the C4A, and permeability ranging from 12 to 158 in the C4A. I will return to this exhibit a couple of times throughout the testimony as we get-- go through the gross thickness and net pay. Net pay. Net pay was determined from the following criteria. Minimum porosity of 15 percent, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-$876 28 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 volume clay less than 28 percent, and volume glauconite less than 40 percent. If the volume of siderite exceeded 30 percent, the net pay was discounted by a factor of 0.5. Exhibit II-1 shows gross thickness by zone based on marker picks, and net pay based on the log model criteria. The 15 percent porosity cutoff corresponds to approximately one millidarcy of permeability and what could be reasonably expected to be a reservoir. Exhibit II-6 shows a cross block of porosity versus permeability. And this label -- this exhibit is labeled confidential. If there's anyone not associated with the owners or ..... THE CHAIRPERSON: You may -- well, we may want to hold on a second because right now we're on a public record so everything that you are testifying to right now is in will be recorded and available to the public so if we want to move into a confidential session, then we'll need to consider that application. If you wish to do it, say, at a later ..... MR. POSPISIL: Would you like to see the exhibit, or can you accept it? It's a power transform to porosity. THE CHAIRPERSON: This document was filed under seal before with the Commission? Or was this the first time? In the original application, was that document METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 29 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 provided? A This was not in the original. THE CHAIRPERSON: In the original, okay. A Actually, this was in the June 15th submission. THE CHAIRPERSON: It was? A This document was, yes. THE CHAIRPERSON: Are there any other exhibits that you are requesting be kept confidential? MR. POSPISIL: Confidential exhibits. A Yes, there are. The Supplement number 1, which we'll be showing with the Borealis information, the comparison between Borealis and Aurora. THE CHAIRPERSON: Anything else other than the supplemental? That hasn't been submitted yet, is that correct? MR. POSPISIL: Correct. A That's correct. THE CHAIRPERSON: Okay. So the only exhibit that has been submitted that you wish to keep confidential is this one ..... A Correct. THE CHAIRPERSON: ..... so far? A That's correct. THE CHAIRPERSON: And the basis for the request that it be maintained confidential? Is this METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 3O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 proprietary? MR. POSPISIL: Proprietary information. A Proprietary, yeah. THE CHAIRPERSON: I'm sorry, what was the number of that exhibit again? II-6? A II-6. THE CHAIRPERSON: And for the record, if this information were to be made public, would the company risk losing some economic value as a result of that? MR. POSPISIL: That's correct. THE CHAIRPERSON: If you are going to use that for purposes of the hearing, then we should proceed into a confidential portion of the hearing which we can move into and have a separate tape and make sure that the room is cleared of anybody who is not eligible to see that. If you wish to handle that separately at the time when we go with the supplemental exhibits, we can do that at that time if you'd like. A Let's do it at that time. I think it'll be easier. THE CHAIRPERSON: Okay. A (By Mr. Bakun) To continue along with water saturations. Water saturations for the Aurora reservoir model were derived using mercury injection capillary pressure analysis, MICP, from S4 and S16 core. The distribution of the data was characterized METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 31 9 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 using two distinct leverage A functions for rock with greater than 21 millidarcy, and less than 20 millidarcy permeability. The capillary pressure data were then used to initialize the Aurora reservoir model utilizing initial water saturations as is shown in Exhibit II-1. The sixth column, it does show the initial average initial water saturations based on the Aurora log model, ranging anywhere from 30 to 66 percent. Relative permeability. Relative permeability curves to the Aurora Pool were derived by comparison to analogs on the North Slope. The crude oil from Aurora was evaluated against other North Slope reservoirs. In terms of API gravity and chemical composition, the Aurora crude most closely resembles Prudhoe Bay and Point McIntyre crude. The Kuparuk Sands within the Aurora Pool resemble two Point McIntyre rock subtypes referred to as rock type number six for permeability greater than 20 millidarcies, and rock type number eight for permeability less than 20 millidarcies. The relative permeability curves generated for these Point McIntyre rock types were employed in the Aurora reservoir model. Wetability. Based on the relatively light nature of the Aurora crude and relative permeability METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 32 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 data from the Point McINtyre analog, the reservoir is expected to be intermediate to water wet. Initial pressure and temperature. Based on RFT data from V-200, the initial reservoir pressure is estimated at 3,433 psia at the reservoir data of 6,700 feet tvd subsea. The reservoir temperature is approximately 150 degrees Fahrenheit at this datum. Fluid PVT datum. Reservoir fluid PVT studies were conducted on V-200 crude from recombined surface separator samples and RFT downhole samples. The reservoir pressure was 3,433 psia at 6,700 feet tvd subsea. The api gravity was 29.1 degrees with a solution gas-oil ratio GOR of 717 standard cubic feet per stock tank barrel. The formation volume factor was 1.345 reservoir barrels for stock tank barrel, and the oil viscosity was 0.722 centipoise at reservoir pressure and temperature. The bubble point for Aurora crude varied according to the sampling method. RFT samples from V-200 had bubble points ranging from 3,028 psig to 3,590 psig. This dispersion is most likely due to the sampling process. The recombined surface samples had a bubble point of 3,073 psig. Exhibit II-2 shows a summary of fluid properties for the Aurora accumulation. This exhibit provides a fundamental reservoir METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 33~ 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 data. Initial pressure and bubble point, 3,433 psia, reservoir temperature 150 degrees, oil gravity ranging from 25 degrees to 30 degrees, reservoir oil viscosity .722 centipoise, water viscosity .45 centipoise, gas viscosity .022 centipoise, solution gas-oil ratio 717 standard cubic feet per stock tank barrel, oil formation volume factor 4.345 reservoir barrels per stock tank barrel, water formation volume factor 1.03 reservoir barrels per stock tank barrel, and the gas formation volume factor at 0.843 reservoir barrels per 1,000 standard cubic feet. Exhibit II-3 contains a listing of PVT properties as a function of pressure. And this is differential liberation data starting at 3464 and dropping to zero psig, and of course the formation volume factors, gas factor, oil viscosity, gas viscosity, and solution GOR at the various pressures. 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 and 146 million stock tank barrels of oil. The difference is primarily due to uncertainty in the gas-oil contact. Formation gas in METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 34 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 place ranges from 75 to 100 million standard cubic feet, and gas cap gas ranges from 15 to 75 million standard cubic feet. Reservoir performance. Well performance. Eight wells have been tested in the Kuparuk Formation at Aurora. Five of the test wells, Beechey Point State number 1, Beechey Point State number 2, North Kuparuk 26-12-12, V-200, and S24A are unavailable for Aurora production. Six development wells have been completed and tested in the Kuparuk: S-100, S-101, S- 102, S-103, S-104, and S-105. The Beechey Point State number 1 well was tested twice producing 1.334 million standard cubic feet per day of gas, along with 17.8 barrels per -- barrels of oil per day at condensate, and 2.7 million standard cubic feet of gas in the second test. A GOC pick was not clearly defined, but based on interpreted wire line log and test data, the GOC is possibly at 6,678 feet tvd subsea, but could range from 6,648 feet tvd subsea to 6,705 feet tvd subsea. Pressure build up analysis indicates that the Kuparuk Sands were badly damaged with a skin excess of plus 50. In Beechey Point State number 2, an attempt to test the Kuparuk horizon was made, but the formation would not flow. It is suspected that the Kuparuk Sands were badly damaged during drilling based METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 35 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 on the high skin from Beechey Point State number 1. An oil-water contact is interpreted at 6,835 feet tvd subsea from side wall core data and logs. The North Kuparuk 26-12-12 well had three flow tests performed in Kuparuk. The first test produced eight barrels of oil over two to six hours. The second produced 32 barrels of oil per day, and a third, 28 barrels of oil per day. An oil-water contact was interpreted at 6,812 feet tvd subsea from logs. Oil api gravity ranged from 25.2 to 26.4 degrees. The V-200 encountered oil in the Kuparuk and a free water level was calculated from RFT pressure data at 6,824 feet tvd subsea. The V-200 was tested in four stages while progressively adding perforations up hole. The initial test with perforations at 6,900 to 6,920 feet md tested at 387 barrels of oil per day with a GOR of 541 standard cubic feet per stock tank barrel. The production tests opened an additional 20 feet of formation, 6,680 to 6,920 feet md, and tested at 1,517 barrels of oil per day with a GOR of 535 standard cubic feet per stock tank barrel from both intervals. After the second set of perforations was added, surface pvt samples were collected, and the pressure transient analysis was performed. The third production test opened a further 18 feet of formation METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 36 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 6,862 to 6,920 feet md, and tested at 1,801 barrels of oil per day with a GOR of 677 standard cubic feet per stock tank barrel from all three intervals. When the well was logged, a final production test flowed at a rate of 1,915 barrels of oil per day, with a GOR of 718 standard cubic feet per stock tank barrel from all three intervals. The S-24 AI well was not flow tested, but RFT data was collected. The entire Kuparuk interval was oil-bearing and no gas or water contact was detected. The RFT pressures and oil gradient were sufficiently different. Eleven psi at common datum from V-200 to suggest that S-24 AI fault block is isolated from the V-200 fault block. The api gravity of the RFT samples was 25.6 degrees. S-100 was drilled as a horizontal well in the V-200 fault block and phase I of Aurora development drilling. Log analysis indicates S-100 has over 1,500 feet of net pay. The well was brought on line in November 2000, and the initial well test produced 7,230 barrels of oil per day, and a GOR of 831 standard cubic feet per stock tank barrel. Initial api gravity was 26~degrees. S-lO1 was drilled as a horizontal well in the southern portion of the V-200 fault block as the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 37 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 second well of phase I development drilling. Log analysis indicates the well has over 2,500 feet of net pay. A December 2000 production test produced 1,062 barrels of oil per day at GOR of 20,707 standard cubic feet per stock tank barrel. Well logs suggest the possible GOC in the toe of the well at approximately 6,680 feet tvd subsea. Initial API gravity was 47 degrees. The elevated API was due to the production of gas and condensate liquids. S-102 was drilled as a horizontal well in the northern portion of the V-200 fault block as the third well of the phase I development drilling. Log analysis indicate that the well is approximately 600 feet of net pay, and that, the reservoir is of considerably lower quality than that for the S-100 and $-101 wells. A December 2000 test produced 458 barrels of oil per day at a GOR of 1,205 standard cubic feet per stock tank barrel. Initial API gravity was 26 degrees. THE CHAIRPERSON: Mr. Bakun, excuse me just a second. If all of the material that you are reading from is included in this packet, if Ms. Heusser doesn't have an objection, I was going to suggest perhaps if you would like since you've been sworn, if you would like to adopt this portion as your testimony, if you would like to tell us what METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 38 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 pages those are? A Sure. THE CHAIRPERSON: And if you would prefer to summarize or just go straight to questions, we could do that and perhaps save your vocal chords a little bit. A Certainly. THE CHAIRPERSON: So if you could for the record then just identify the pages on this July 23rd document that you are adopting as your testimony, that may help me out a little bit. A It'll be pages 10 through page 18. THE CHAIRPERSON: That's correct. THE CHAIRPERSON: Page 10 through 18. You're certainly welcome to keep reading if you'd like but I thought if that might help some of you get through that ..... A No problem. THE CHAIRPERSON: Okay. A I would like to jump to a couple of quick things just for -- just to show I think a couple of key points under development planning. THE CHAIRPERSON: That would be great. Thank yOU. A And this comes under the model results looking at a comparison of primary recovery versus water flood METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 39 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 recovery, on page 15. The primary recovery mechanism in the Aurora Pool would be a combination of gas cap expansions, solution gas drive, and possibly limited aquifer influx from the periphery. Model simulation suggest that would recover approximately 12 percent of the oil initially in place, and that the pressure flow field would drop below 2,000 pounds by year 2006 producing at a peak rate of 7 to 9,000 barrels of oil per day. Contrast this with Exhibit II-5, it shows water flood recovery for the Aurora Pool, which shows an oil recovery on the order of 34 percent of the oil initially in place, peak production rates of 14 to 17,000 barrels of oil per day, and a maximum water injection rate of 20 to 30,000 barrels of water per day. At this point I would also like to point out that our reservoir management strategy is once water injection commences, we will inject at a VRR of greater than 1.0 to restore reservoir pressure. At that point we will inject a balance of VRR, and we feel that this strategy is a dynamic process that will approach Aurora surveillance, the dynamic process through the life of the field looking for ways to maximize ultimate recovery as we move through METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 4O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 development. And that concludes my testimony on the reservoir description section. THE CHAIRPERSON: Okay. Ms. Heusser, do you have some questions? COMMISSIONER HEUSSER: Yes, I do. A And from here, we do have the confidential section. If we'd like to move there, that may help answer some of the questions that were brought up in the geology section, or should we take questions. THE CHAIRPERSON: And were you planning on presenting that testimony? A Yes, I was. THE CHAIRPERSON: Do you want to wait and do that first? BY COMMISSIONER HEUSSER: Q My questions are -- my current questions are primarily around just what you've presented so far. A Okay. Q You've just demonstrated that there's a significant benefit associated with a water flood at this reservoir. When do you anticipating evaluating miscible injection? A We have performed initial screenings on miscible injectant. Early studies indicate an incremental METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 41 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A A recovery on the order of five percent. We are currently continuing the evaluation process with experts within BP, and we are hoping to have results on that some time later this year. So is it safe to assume that the source of the miscible injection is -- injectant Prudhoe Bay? That is one of the options we are considering. And you referenced some fluid pvd data, and you develop kind of a generic profile. Will you be providing -- when will you be providing the specifics of the -- all the wells that were used to develop that pvd profile? It was my understanding that you were going to ..... This pvd profile. Right. What about here on page 11, you provide some fluid properties, it was my understanding that you were going to provide the range of fluid properties, the specifics of the range of fluid properties, specific by well? For the oil field. And oils. Yes, that's in the ..... Actually, wasn't it across from Kuparuk all the way across to Prudhoe? We do have some of that data in the supplemental section. The supplemental section? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 42 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A Yes. Q Okay. And is that where you're going to be providing the details of the fluid composition is in the supplemental portion? A Yes. Q Okay. THE CHAIRPERSON: Mr. Bakun, how long do you anticipate the confidential portion of testimony taking? A Probably 10 to 15 minutes. THE CHAIRPERSON: Okay. Should we go ahead and change tapes and do that? And for the record, if' you would just put on the record why you're asking that that portion remain confidential? MR. POSPISIL: Okay. That portion of the submission was provided in order to answer questions presented by the AOGCC staff to us, questions in the area of the nature of the porosity perm transform and specifically the data that went into that. And then secondly, to prepare the Aurora and Borealis net oil pore volume and the extent of each. THE CHAIRPERSON: And the nature of the reservoir data that you're going to be providing is confidential because that's proprietary information? MR. POSPISIL: That's correct. THE CHAIRPERSON: If you could identify then in the room who is allowed to stay or who needs to leave? We METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 43 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 can identify for you the members of the Commission staff, but ..... MR. POSPISIL: Okay. So the staff and owner ..... MS. NELSON: I know I get to leave. (Laughter) THE CHAIRPERSON: Then I was going to suggest we take a break right after that. MR. POSPISIL: Okay. (Confidential session) (Resume public hearing - 11:26 a.m.) A (By Mr. Bakun) I would just like to make -- since we're back on the public record, I would like to make one adjustment to the typographic area, and there is a water description section. Q (By The Chairperson) On what page? A On page 12, under well performance, the second paragraph where it gives the gas rates for the Beechey Point State number 1 well, those should both have a decimal point and it should be 1.334 and 2.700. Q 1.334. There's a decimal point between the 1 and the 3, and between the 2 and 7? A That is correct. Q Okay. Thank you. A Thank you. And that concludes ..... METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 44 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A Yeah. THE CHAIRPERSON: THE CHAIRPERSON: (Witness excused) THE CHAIRPERSON: (Oath administered) MR. YOUNG: I do. Your testimony? Thank you. Raise your right hand. JAMES PATRICK YOUNG having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION THE CHAIRPERSON: provide expert testimony today? A Yes, I do. THE CHAIRPERSON: Do you wish to be -- to Would you please state your full name for the record, spell your last name, and then proceed to give your qualifications? A My name is James Patrick Young, Y-o-u-n-g as in gulf. I am an engineer for BP Exploration Alaska. I am currently working as a petroleum engineer for the Aurora development project. I have received a bachelor of science degree in petroleum engineering from Montana Tech. I joined BP in 2000 via the acquisition of ARCO and have worked in Alaska on a variety of projects since 1992. I have been working METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 995021 (907) 276-3876 45 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 with the Greater Prudhoe Bay Western development area since August 1999. I would like to be acknowledged as an expert witness. THE CHAIRPERSON: Do you have any questions? COMMISSIONER HEUSSER: No, I don't. THE CHAIRPERSON: Any objections? Mr. Young, you're in the same position as the other witnesses have been so far. Is there specific testimony that you would like to have adopted as your testimony and just summarize, or would you prefer to read it into the record? A If you will allow, I would prefer to just summarize it for you and give you the pages. THE CHAIRPERSON: Well, for purposes of adopting your testimony into the record, could you identify which pages would be your testimony? A The pages of my testimony begin with page 19, facilities, continue through Well Operations, into area injection operations, production allocations, and -- and at the -- on page 34 at the end of the area injection operation section. THE CHAIRPERSON: Okay. So it would be page 19 through 34? A 19-34, correct. THE CHAIRPERSON: You may proceed to summarize your testimony. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 46 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A Okay. The Aurora wells will be drilled from the existing IPA drill site, S-Pad. In Exhibit III-1 there's a diagram of where the -- the Aurora wells will be located on S-Pad showing the production headers and gas lift lines that will be used to lift the wells. Production will be brought to the GC2 production facility at Prudhoe Bay via a 24 inch low pressure diameter flow line, a 10 inch gas lift supply line, and a water working into water injection supply line. Also, an eight inch MI supply line from GC2 to the S-Pad could be utilized for future EOR applications. These are the lines as they extend from -- from S-Pad to the northern end of S-Pad, and the wells tie back into the main manifold building at S-Pad. A larger view shows a larger diagram of the wells on S-Pad and where they would tie into the existing production header. That takes S-Pad production back to GC2 facility. ' Because Aurora wells can be drilled from S-Pad and tied into existing facilities at S-Pad, no new roads or road work will be required to develop Aurora Field, and no new facilities will need to be designed to -- for initial production. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 47 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 The water injection capacity available currently to S-Pad wells is expected to deliver the required injection rates for Aurora wells of 2,000 and 2,100 psi, and rates of a total of 25 to 30,000 barrels per day of water. Artificial lift gas will also be supplied from the S-Pad gas lift system which provides gas lift pressure up to 18 to 1,900 psig adequate to lift Aurora wells. Production allocation will be addressed in Section 5. It is currently based on the interim metering plan which was approved November the 15th, 2000. This requires a minimum of two well tests per month through the S-Pad separator, and daily production is based on a straight interpolation between well test. It is designated as -- Aurora will be designated as an allocation of 1.0 for the inner metering plan, and the wells are monitored through the Skata (ph) Data Acquisition System that is currently used for other S-Pad wells. As mentioned earlier, Aurora production will be brought back to GC2 production facility which was processed to -- to be able to process a nominal rate of 400,000 barrels of oil per day, 320 main standard cubic feet per day, which has subsequently been increased to 1.2 billion standard cubic feet per day, METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 48 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 and nominal water rate of 280,000 barrels of water per day. Production including that from the Aurora reservoir is not expected to exceed existing GC2 capacity. For the well operation section, I would just like to highlight that as of the day of this application, six development wells have been drilled: wells S-100, 101, 102, 103, 104, and S-105. The Exhibit Roman numeral IV-1 shows a typical vertical completion for Aurora vertical well, which is a 80 foot conductor, 20 inch 80 foot conductor casing, '9-5/8 or 7-5/8 casing set no shallower than 2,300 feet subsea, and then a seven inch long string or 5-1/2 inch long string casing to -- to penetrate the Kuparuk Formation, and completed with tubing range -- sizes ranging from 2-3/8 to 5-1/2 inch tubing depending on well productivity. Exhibit IV-2 is a horizontal well completion which was used for S-100 the first produced development well at the Aurora Field, which is a seven inch casing which has landed in the top of the Kuparuk reservoir similar to the vertical wells, and then the -- the horizontal section is drilled with the smaller hole size and completed with a 4-1/2 inch production casing and perforated for the for METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 49 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 production. Other Aurora wells will either be slotted liner up through the horizontal section, or a combination of cemented and slotted liner in the Kuparuk reservoir. Some wells at Aurora will be combined in the future with -- for multiple injection into either the Schrader Bluff reservoirs, or the deeper Ivishak reservoirs, and these will be selected based on compatibility of the wells, and this will be an example of a completion that we have in S-104 that isolates pressures from the Kuparuk injection to the shallow Schrader Bluff injection. Subsurface safety valves. There is no requirement for subsurface safety vales in the Aurora wells under the applicable regulation, 20 AAC 25.265. Moreover, in light of developments in oil field technology and controls in experience in operating in the enviro- -- arctic environment, the Commission has eliminated subsurface safety requirements for both rules governing both the Prudhoe oil pool and Kuparuk River oil pool. These were exempted in Conservation Orders 363 and 348, respectively. Rule 5 of the Conservation Order 98(a), a rule made in 1971, appears to require subsurface safety valves for the wells. Therefore, the Applicants METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 5O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 recommend removal of the oil pool from the scope of that Conservation Order to be -- and this would also make it consistent with S-Pad and other PB operations at S-Pad. Existing completions are equipped with subsurface safety valve nipples which will be installed in wells, put into MI injection, gas injection service. Ail Aurora wells will have surface safety vales in accordance with AOGCC requirements. In order to minimize skin damage, some wells may be drilled with KCL based mud to minimize formation damaged at the Kuparuk Formation. And stimulation may be necessary to bypass completion damage in wells that are not drilled at ACL wells that are underperforming. The reservoir surveillance program will entail a minimum of two pressures per year, be obtained annually from each side of the main Aurora field from each side of the main dividing fault block, which divides the V-200 Block from the North of Crest Block and the Crest Block, and surveillance logs may include flow meters, temperature logs, or other prudent diagnostic skills to determine reservoir performance. Final section, product production allocation, as mentioned earlier, eventually will be done METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 51 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 according to the PBU western satellite production metering plan after that plan is improved. In the interim, Aurora wells will be tested twice per month and with a land interpretation between well tests to interpret daily production. And they will be based on an allocation factor of 1.0. We request that Commission approval under 20 AAC 25.215 that the Aurora metering exceeds the requirement for monthly well tests, or as an acceptable alternative. Section 6 covers the area injection operations. BP as a designated operator of the Aurora participating areas, Surface owners within a quarter mile radius and inclusively, the Aurora participating area are as follows: State of Alaska, BP, and there's an affidavit in Exhibit V-1 showing the operators and surface owners within one-quarter mile radius of this area. Exhibit V-1. The injection well casing will be converted -- two wells initially will be proposed to convert to injection. The $-101 and the S-104I wells will be converted to inject service for the Aurora enhanced recovery project. These wells will be casing and have been permitted in accordance with 20 AAC 25.030, and these are shown -- the schematics for these were shown in Exhibits IV-2 and IV-3, showing the details of the METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 52 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 completions for these wells. A cement bond log indicates good cement bond across the Kuparuk in the S-105 was -- further logging will be necessary to confirm integrity in S-1 before injection can commence. The Aurora enhanced recovery project will use GC2 produced water. In Exhibit IV-4, is a comparison of Kuparuk Formation water obtained from the S-105 well. Production water from a Kuparuk C Sand compared with a GC2 produced water which will be used for injection. The produced water is -- is primarily a mixture of sea water and -- and Ivishak produced water, and is expected to be compatible with the S -- with the Kuparuk River Formation. Injection pressures. The average surface water injection pressure for the project is 1,800 psi. The maximum -- estimated maximum surface impression would be 3,000 psi, and the resulting bottomhole would be limited to -- by hydraulic pressure losses in the tubing would never exceed 6,000 psi. The maximum expected injection pressure will not initiate or propagate fractures through confining strata, and will not allow injection of formation flow to any freshwater strata. There is no evidence of injection out of zone with similar Kuparuk River Formation METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 53 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 waterfloods on the North Slope. The Kuparuk reservoir is bounded by the Kaluvik and HRZ shales above the Kuparuk reservoir which have combined thicknesses of greater than 110 feet in the Kuparuk area, and have demonstrated with -- with logs and formation integrity tests to have a fracture gradient of .8 to .9 psi which would allow us to inject into the Kuparuk at designed pressures, and not exceed this fracture gradient. The Aurora -- as mentioned earlier, the Aurora Pool estimated to have 110 to 146 million stock tank barrels in place, and simulation studies indicate incremental cover to be between 15 to 25 percent of original oil in place relative to primary completion. The final section covers the proposed Aurora Pool rules which we have submitted a draft for your review. At this point, I would like to open up for questions before we go into this, we can go -- step through the pool rules. THE CHAIRPERSON: Mr. Pospisil, do you know did you receive an e-mail from Tom Monder (ph), a petroleum engineer? It would have been late yesterday afternoon. MR. POSPISIL: Yes, we did. THE CHAIRPERSON: Okay. MR. POSPISIL: And we have we can respond METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 54 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 to questions included within that e-mail. A Yes, we have. We have a written response to those questions, and we can -- I can go through which of those you would like to, or all of them, as you wish if you want to. THE CHAIRPERSON: If -- well, if they're in writing, maybe we could just get some get a copy and ..... MR. POSPISIL: That's correct. We can provide a copy. A Okay. We'll have a copy, available copy. COMMISSIONER HEUSSER: Mr. Young, I need some clarification here. BY COMMISSIONER HEUSSER: Q Looking back at page 24 where it talks about the proposed wells. They'll be concluded in a single zone. I'm going to be referencing an earlier part of your packet, page ..... UNIDENTIFIED MALE SPEAKER: (indiscernible) Q Yeah. Okay. It is page 24 on both packets. So the - - you've got a discussion here that talks about single zone completions and multi zone completions using a single string and packers. And then you go on to say that for multi zone wells, wells will have gas lift mandrels to provide flexibility for artificial lift or commingle production and injection. Could you clarify METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 55 10 11 12 13 14 15 16 17 18 19 2O 21 ¸22 23 24 25 Q A for me whether or not it's -- you'll have a single well that will be injecting and producing at the same time? Is that your intention? No. The intention here was to provide the fact that we have completed wells to be capable of commingled injection, which we have not brought forward to the Commission because of the zone of interest because the State of Alaska has not proposed for area injection operations yet, and that there will not be production and injection in the same well. It will be just multiple zones of injection, and in an injection well. Or if we have approval, we propose it will be multiple injection -- multiple production of zones from one well, and not production or injection -- an injection of the same well. So you're not proposing it now but it's ..... Right. ..... basically your intention to commingle production in the future from between the Kuparuk and the Sag and the Ivishak? Most likely the Kuparuk and the Schrader Bluff. We are still working through the options bringing a case for that, that we can do that, effectively get the same level of allocations and production allocations that we can at the surface. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 56 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Q When will you be bringing that information to us? A Possibly in by the end of 2002. It's -- it's at least a year away. THE CHAIRPERSON: Perhaps we could take a look at your written response to questions because if we have other questions that you may have already answered in the written document ..... A Okay. THE CHAIRPERSON: Thank you. COMMISSIONER HEUSSER: Thanks. (Pause - reviewing document) THE CHAIRPERSON: Who gets to answer questions on the safety valves and subsurface safety valves? A I can answer some of these questions. MR. POSPISIL: He will start. THE CHAIRPERSON: Thank you very much for this written response, too. We appreciate it. With respect to the risk assessments that were done on hazard analysis, is this a document that was filed with the Commission some time ago as part of the request to remove subsurface safety valves, or is this something new that we don't have on file? A (By Mr. Bakun) The records we obtained yesterday from the Commission I think were --. .... THE CHAIRPERSON: Included that? A ..... -- included that. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 57 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 THE CHAIRPERSON: So that would have been part of the conservation order? UNIDENTIFIED MALE SPEAKER: The summary and the tables were. A I forget what conservation order. Three, sixty-three. THE CHAIRPERSON: There are two of them I believe. A Yeah. UNIDENTIFIED MALE SPEAKER: Right. A Two of them. THE CHAIRPERSON: So it's been included in that packet. Okay. So we have those on file. A Yeah. THE CHAIRPERSON: Has there been any work done since then with respect to subsurface safety valves? A Not to my knowledge. MR. SMITH: No, the exact numbers -- (indiscernible - away from microphone) Petroleum, Borealis, BP. The actual analysis that was done has been reviewed coarsely, that the actual data was considered as similar. That is, the actual evaluation has provided the same answer for what we've seen. We've seen no change in the data base for the consequences of this. So -- and the actual risk analysis that evaluated in '74/75 or excuse me, '94/95 is considered the same and still valid. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 58 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 THE CHAIRPERSON: Okay. Thank you. Well, as many of you know, the Commission and the State as a whole has come under some scrutiny and criticism for its original order back in the '90s for blanket releasing the subsurface safety valves, and at least one state agency has called upon a review -- a Commission review of that determination. So do I understand then that your answers to these questions rely on that analysis for the determination? MR. POSPISIL: We were specifically asked to provide information as far as a risk assessment so that area of a risk assessment is based upon that '94 survey which as Bruce mentioned we have reviewed more recent data, and believe that that -- the results and conclusions from that are still valid. So that, we have updated that in terms of Aurora. We've also' looked at the specifics of the well designs and the operations at Aurora, and our proposal is consistent with that in terms of subsurface safety valve requirements. THE CHAIRPERSON: What kind of safety valves, surface safety valve systems are you using on those wells, the Aurora wells? MR. POSPISIL: You'll get that. A (By Mr. Young) Hydraulically, the actuated wells with a pilot system which shuts in the well down automatically based on an upper limit pressure and a lower limit pressure. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 59 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 THE CHAIRPERSON: The reason I ask is I understand from practices across the Slope that some fields do better than others, and I didn't know if there was a difference in hardware. MR. SMITH: There is changes that are between the different systems themselves. Both hydraulic and the electric system are now being evaluated for being installation -- being installed for (indiscernible) and for other pads that are in general, that the general design of the equipment itself is similar to the other Prudhoe Bay installations currently. COMMISSIONER HEUSSER: So I heard you mention electric pilots. Now, I believe that those are used at Nome and they have a pretty good track record with respect to a very low failure rate, and so -- but I think I just heard you say that what's going to be installed for these wells is similar to although perhaps more model version of what's currently in place at the Prudhoe Bay field? MR. SMITH: The pilots themselves on S-Pad are electric. electric? COMMISSIONER HEUSSER: The pilots are MR. SMITH: That's correct. The hydraulic system for the surface safety valve itself, the current equipment that is in place is a hydraulic system at both Milne METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 6O 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 Point and at Prudhoe. So but the pilots themselves will be electric, and that's the current system. The hydraulic systems for the pilots themselves have been phased out, and they've been changed over to electrical, all new installation. COMMISSIONER HEUSSER: Thank you. COMMISSIONER HEUSSER: Could we be provided with a copy of the results in whatever level of detail is appropriate of your recent subsurface safety valve assessment? MR. POSPISIL: Sure. BY COMMISSIONER HEUSSER: Q I have a question with respect to the proposed level of reservoir surveillance, reservoir pressure surveillance. Okay. I believe I heard you say that you'll be taking -- you propose to take two pressure measurements on the west side of the north -- the main north-south fault, and two on the east side, is that correct? A (By Mr. Young) Well, it's two total, so it would be at least one on each side. Two in the field, a minimum of two pressure surveys in the field, and one on each side. Q For my own curiosity, since you've identified stratigraphic blocks, five different ones, why aren't you concerned one per stratigraphic block? (By Mr. Young) We most likely will for surveillance A METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 61 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A purposes, for our purposes. At the time we made these pool rules, we were hadn't really determined if we wanted to have that in the pool rules or not. At that time we felt it would be more flexible to have this even though our surveillance is typically more extensive than that. (By Mr. Bakun) If I could add, already we've collected six statics I believe in the V-200 Block alone. We feel that the early time is when we need the majority of the surveillance data, particularly prior to and just after starting waterflood operations for our surveillance data base. What we see the two pressures as is sort of longer term, getting out several years into the development of the field where we're in a stable waterflood environment where the VRs are balanced and we wouldn't expect to see much change, but we would like to still collect a minimum of data, but in the interim, we will definitely be collecting more data. So if I heard you correctly, then basically the majority of your reservoir pressure surveillance will occur prior to waterflood in the early years of waterflood in order to provide you with pattern balancing? (By Mr. Bakun) Gauges with the affects of pattern METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 62 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A balancing. This probably where we're going to be able to confirm how the blocks are actually talking to each other. Are they truly isolated. Are the faults semi ceiling. Are they sand on sand truly talking to each other, and I think that's why we feel in the early time we'll definitely be collecting more data than we would. Once we get into the stable VRR of one environment where we're just in steady state waterflood operation. You know, I don't remember seeing anything on your proposed waterflood plans. Is there -- do you have any idea whether or not it's going to be -- what kind of pattern flood it might be, or is it ..... It's in the reservoir development section. Did I miss that? Section II. Yeah. I apologize. I went quickly over that. On a short synopsis, on the V-200 fault block, we currently have the three wells there. We plan to convert S-101 to injection, and right now the wells are in about a 480 acre irregular space patterns. The irregular patterns of course are due to the complex fault picture. We were actually trying to tailor the well placement to what our interpretation of what the reservoir is. The North of Crest area, our wells are approximately 120 acre spacing. And, again, with S- METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 63 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 104 as mentioned in Jim's testimony, it will be converted to water injection. Q Thank you. And I see that your -- you've mentioned a minimum well spacing of 80 acres. Would the irregular patterns that you might well expect, is there some reason why you haven't requested a minimum well spacing of 40 acres? A No. COMMISSIONER HEUSSER: Okay. I believe that's all my questions. THE CHAIRPERSON: It is actually the noon hour but it also looks like we're just about nearing the end, so I'll leave it up to you. Do you want to just keep going until we finish? MR. POSPISIL: (Nods head affirmatively) THE CHAIRPERSON: Okay. Mr. Young, were you going to proceed with the pool rules then? A (By Mr. Young) At this point, I was going to ask if we do want to step through those. We've basically provided those as a reference for review, a review of those draft pools will be acceptable, and we would also like to pursue a timely response to our application so we can commence water injection. So ..... THE CHAIRPERSON: How soon are you hoping to METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 64 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 begin water znjection? A We would like to start the first week of August. THE CHAIRPERSON: First week of August, okay. With respect to -- let me look at the pool definition and the affected area for injection, I just want to verify what I think looks to me like just a typographical error, but on your Exhibit I-3, or I-3, it appears to me that the pool boundaries, the rule boundaries and the area injection order boundaries that you are looking for track the surface boundaries of Exhibit I-3, is that correct? A (By Mr. Bakun) That's correct. The -- it includes the initial or our participating area which is in the solid line, plus all of the area in the dashed lines for the automatic expansion areas. THE CHAIRPERSON: I tend to get lost on multiple lines of repeated numbers, when I look at the actual affected areas that's described there, it looks to me like Section 30 is not on there. A It's just a corner of expansion -- automatic expansion area four. Is that ..... THE CHAIRPERSON: That's correct. That looked to me like it was left out, but I may have missed it going over all those numbers. I just wanted to confirm that that should be included. A (By Mr. Young) Good point, yeah. Have to look. it METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501, (907) 276-3876 65 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 should be included. Yeah, we may have left it out on the description. THE CHAIRPERSON: Well, it's easy enough for us to fix. We just wanted to make sure that we were adding it correctly. MR. POSPISIL: Right. That's correct. That's our intent. A Yeah, what's on the map is correct. A (By Mr. Cerveny) Yeah, I think you're right. THE CHAIRPERSON: The only other -- just a minor detail. Sorry. On rule number two of the pool rules with the proposed pool definition and under rule number one for the area injection application, referring to the authorized injection strata, you're using the V-200 well but the depth that you used for the pool definition is the lower number 7,253.5. You're using 7252 for the area injection application. A (By Mr. Young) Probably just a rounding error. THE CHAIRPERSON: Okay. As long as there wasn't a specific reason that we were looking for that. A No. THE CHAIRPERSON: Okay. And then with respect to the additional information that the Commission has requested, how much time would you ask that the record be left open so that that information can be provided? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 66 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 MR. POSPISIL: I would expect that we could provide this within a week. Is that ..... THE CHAIRPERSON: By next Tuesday? Okay. So we'll keep the record open until next Tuesday at 4:00 o'clock. MR. POSPISIL: Any other concerns with that timing? Very good. THE CHAIRPERSON: Okay. We can certainly begin evaluating some of this information. However, we can't promise having an order to you. I understand we're looking at -- that's the first week of August -- well, I guess first of August starts next week. MR. POSPISIL: Sure. THE CHAIRPERSON: Okay. But we'll keep in mind the date that you want to get started as early as possible. I think that's all I have because the western satellite production metering plan is attached to the new document so I think I have everything that I was looking for. BY COMMISSIONER HEUSSER: Q The production -- the attached metering plan, does it specify a well test one or -- once or twice a month? A (By Mr. Young) It's once per month. Q Once per month? A Yeah. Q So page 36, first paragraph D where it specifies well test two times per month, that should really be one? METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 67 10 11 12 13 15 16 17 18 19 20 21 22 23 24 25 A A on? THE CHAIRPERSON: That's their proposal, yes. Yeah, the interim plan would be -- is two, but once the western satellite metering plan, it would be one. Okay. This is a question that I should have asked during either the geological or the reservoir presentation so excuse me for asking it after the fact. But I have a note here to myself. Looking at your average properties by simulation layer, I'm looking at Exhibit Roman number II-l, not a layering in properties, and the question that I have is what future coring plans do you have to calibrate NWD and RWD log responses? And in any fault blocks that you might enter into? (By Mr. Cerveny) I don't think there's any coring plans. COURT REPORTER: Sir, would you put the mike Currently, I don't believe we have any plans to collect anymore core. Okay. So basically your NWD logs are going to be calibrated on existing -- will continue to calibrated using existing core data? Existing core. We have decent core coverage in the area, as well for S-16, S-4 and ..... (By Mr. Young) Sidewall cores. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 68 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 A (By Mr. Cerveny) ..... sidewall cores and a number of wells. Q Out of curiosity, was different core data used to calibrate for Borealis interpretation? A Yes. COMMISSIONER HEUSSER: Okay. That's all my questions. Thank you. THE CHAIRPERSON: That's all my questions. Thank you very much. And thank you very much also for providing additional last minute information and answers to questions that we fired off at the last minute. We really appreciate it. (Off record - 12:08 p.m.) END OF PROCEEDINGS METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 69 10 11 12 13 14 15 16 17 18 19 2O 21 22 23 24 25 C E R T I F I C A T E UNITED STATES OF AMERICA) )SS. STATE OF ALASKA ) I, Laura C. Ferro, Notary Public in and for the State of Alaska, and Reporter for Metro Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Public Commission Public Hearing was taken before myself on the 2Ath day of July 2001, commencing at the hour of 9:00 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 333 West Seventh Avenue, Suite 100, Anchorage, Alaska; That the public hearing was transcribed by myself to the best of my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 3rd day of August 2001. Notary Public in and for Alaska My commission expires: 06/03/05 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 #7 BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 bp July 23, 2001 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 FIE: Aurora Pool Rules And Area Injection Application - Supplemental Data Dear Commissioners: Enclosed is a supplemental data set to the Aurora Pool Rules and Area Injection Application. Further an addendum to the Production Allocation portion of the pre- filed testimony is included. Please contact the authors if you have any questions or comments regarding this request. Sincerely, Gordon Pospisil GPB Satellites Manager Attachments Author Name Jim Young Ed Westergaard Bruce Weiler Francis Rollins Fred Bakun CC: Randy Frazier (BP) J. P. Johnson (PAl) Position .... ~' ~,, Office Ops. Eng. 564-5754 Dev. Geologist 564-5972 Facility Eng. 564-4350 Geophysicist 564-4517 Res. Eng 564-5173 M. P. Evans (ExxonMobil) P. White (Forest Oil) Aurora Pool Rules and Area Injection Order 7/23/2001 Aurora Pool Rules And Area Injection Application July 23, 2001 Aurora Pool Rules and Area Injection Order 7/23/2001 I. Geology ........................................................................................................................... 3 Introduction ..................................................................................................................... 3 Stratigraphy ..................................................................................................................... 3 Structure .......................................................................................................................... 7 Fluid Contacts ................................................................................................................. 9 Pool Limits ...................................................................................................................... 9 II. Reservoir Description and Development Planning ..................................................... 10 Rock and Fluid Properties ............................................................................................. 10 Hydrocarbons in Place .................................................................................................. 12 Reservoir Performance .................................................................................................. 12 Development Planning .................................................................................................. 15 Model Results ................................................................................................................ 15 Development Plans ........................................................................................................ 16 Reservoir Management Strategy ................................................................................... 17 III. Facilities ..................................................................................................................... 19 General Overview ......................................................................................................... 19 Drill Sites, Pads, and Roads .......................................................................................... 19 Pad Facilities and Operations ........................................................................................ 20 Production Center .......................................................................................................... 21 IV. Well Operations ......................................................................................................... 22 Drilling and Well Design .............................................................................................. 22 Reservoir Surveillance Program .................................................................................... 26 V. Production Allocation .................................................................................................. 28 VI. Area Injection Operations .......................................................................................... 29 Plat of Project Area ....................................................................................................... 29 Operators/Surface Owners ............................................................................................ 29 Description of Operation ............................................................................................... 29 Geologic Information .................................................................................................... 30 Injection Well Casing Information ................................................................................ 30 Injection Fluids .............................................................................................................. 30 Injection Pressures ......................................................................................................... 32 Fracture Information ..................................................................................................... 32 Hydrocarbon Recovery ................................................................................................. 34 VII. Proposed Aurora Oil Pool Rules ............................................................................... 35 VIII. Area Injection Application ....................................................................................... 37 IX. List of Exhibits ........................................................................................................... 39 2/40 Aurora Pool Rules and Area Injection Order 7/23/2001 I. Geology Introduction The Aurora Pool is located on Alaska's North Slope, as illustrated in Exhibit I-1. The Aurora Pool was confirmed in 1999 by the drilling of the V-200 well. The reservoir interval for the Aurora Pool is the Kupamk River Formation. The Aurora Pool overlies the Prudhoe Bay Unit (PBU) Sadlerochit Group reservoirs in the vicinity of S-Pad. In addition to the V-200 well, the S- 100, S- 101, S- 102, S- 103, S- 104, and S- 105 wells are recent Kuparuk River Formation penetrations in this area. The North Kuparuk 26-12-12 and Beechey Point State #1 wells, both drilled in 1969, were the first wells to penetrate and test hydrocarbons in the Aurora Pool. A number of PBU Sag River/Ivishak development wells also penetrated the overlying Kuparuk River Formation. The S-24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. Four S-Pad and M-Pad well penetrations and Term Well C define the southeastern limit of the Aurora accumulation. As shown in Exhibit 1-2, the top of the Aurora structure crests at 6450 feet true vertical depth sub-sea (tvdss). The deepest interpreted oil-water contact (OWC) is at 6835 feet (tvdss) in the Beechey Point State # 2 well. Exhibit 1-3 shows the location of the Aurora Participating Area (APA), including expansion areas identified by the Department of Natural Resources. The area encompassed by the Aurora Pool would be removed from the Prudhoe Bay Field Kuparuk River Oil Pool rules area under Conservation Order 98-A. Stratigraphy The productive interval of the Aurora Pool is the Kuparuk River Formation, informally referred to as the "Kuparuk Formation". This formation was deposited during the Early Cretaceous geologic time period, between 120 and 145 million years before present. Exhibit 1-4 shows a portion of the open-hole wireline logs from the V-200 well. This "type log" illustrates the stratigraphic definition of the Aurora Pool. The log is scaled in true vertical depth subsea and also has a measured depth (md) track. In the V-200 well, the top of Kuparuk Formation occurs at 6,693 ft. tvdss (6,858.5 ft. md) and the base occurs at 7,070 ft. tvdss (7,253.5 ft. md). 3/40 Aurora Pool Rules and Area Injection Order 7/23/2001 The Kupamk Formation was deposited as marine shoreface and offshore sediments, and is composed of very fine to medium grained quartz-rich sandstone, which is interbedded with siltstone and mudstone. The sandstones typically have higher resistivity (3-50 ohm- meters) than the surrounding lithologic units. The Kupamk Formation base is bounded by its contact with the Early Cretaceous-age Miluveach Formation and is distinguished by a change in lithology and conventional electric log character. The Miluveach Formation is shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation top is defined by its contact with the Early Cretaceous-age Kalubik Formation or the overlying Early Cretaceous-age High Radioactive Zone (HRZ) Formation. Both are shales, and they are distinguished from the Kuparuk River Formation by a change in lithology and conventional electric log character. The Kalubik Formation is a dark gray shale with a Gamma Ray log signature of 80 to 135 API units, and the HRZ is a black, organic-rich shale with a Gamma Ray log signature typically greater than 150 gamma API units. The Kupamk Formation in the Aurora Pool is stratigraphically complex, characterized by multiple unconformities, changes in thickness and sedimentary facies, and local diagenetic cementation. As shown on the type log in Exhibit 1-4, the Kuparuk Formation is divided into three stratigraphic intervals, from oldest to youngest, the A, B, and C intervals, with the A and C intervals divided into a number of sub-intervals. An overlying unit, called the D Shale, is locally present in the northern part of the Aurora Pool. Three unconformities affect Kupamk thickness and stratigraphy. The Lower Cretaceous Unconformity (LCU) has erosional topography. It truncates downward and dips to the east where it successively removes the Kuparuk B and Kuparuk A intervals. The C-4 Unconformity also truncates downward to the east progressively removing the C-4A, C- 3B, C-3A, C-2, and C-1 sub-intervals before merging with the LCU. A younger unconformity, called the Pre-Aptian Unconformity also affects the Aurora Pool. At the Beechey Point wells in the western portion of the Aurora Pool, the Kuparuk Formation is 4~4O Aurora Pool Rules and Area Injection Order 7/23/2001 unaffected and the HRZ interval above this unconformity is in contact with the Kalubik Formation. However, this unconformity also truncates downward to the east. At the V- 200 well and other S-Pad wells to the east, the Kalubik Formation is eroded, and the HRZ interval is in contact with the Kupamk C-4B sub-interval. This Pre-Aptian Unconformity eventually truncates the Kupamk C-4B and the C-4A locally, and merges with the C-4 Unconformity and the Lower Cretaceous Unconformity at the eastern edge of the Aurora area. The Kuparuk A and B units have a distinctly different stratigraphic thickness trend than the Kuparuk C units. Where not truncated, the lower A unit maintains a nearly uniform thickness throughout the Aurora area, suggesting that its deposition pre-dates significant fault movement. In contrast, the thickness, lithofacies, and diagenesis of the C units are variable and have been influenced by differential erosion, and variable diagenetic fluid effects. As a result of these processes, the entire Kuparuk C interval thins south and southeastward and reservoir quality varies laterally and vertically. The lower Kuparuk A interval contains two reservoir quality sub-intervals; the A-4 and A-5 sand units, which are 30 feet and 20 feet thick, respectively. In the V-200 well, these sands are wet. In structurally higher portions of the field to the east, these A sand units are expected to be oil-bearing and productive. The A-5 sand appears to be higher quality reservoir than the A-4 sand. The overlying Kuparuk B interval is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are up to 3 feet thick. In the V-200 well, wireline logs show these thin B interval sands to be wet. The uppermost unit, the Kuparuk C interval, contains the primary reservoir sands of the Aurora Pool. The thickness of this interval 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 lithology of this upper unit is variable, consisting of interbedded very fine-grained to medium-grained sandstone with minor amounts of muddy siltstone and sandy-silty mudstone. The Kuparuk C sands are generally very quartzose and 5/40 Aurora Pool Rules and Area Injection Order 7/23/2001 moderately sorted. The Kupamk C interval is intensely bioturbated, contributing to the heterogeneous nature of the Kupamk C. The Kuparuk C is further subdivided into the following sub-intervals from oldest to youngest: C-l, C-2, C-3A, C-3B, C-4A, and C- 4B. The C-1 overlies the Lower Cretaceous Unconformity. The Kupamk C-1 and C-4B sub-intervals are coarser grained and contain variable amounts of glauconite and diagenetic siderite. The volume and distribution of siderite and glauconite plays an important role in the reservoir quality of the Kupamk C-1 and C-4B intervals. These minerals are unevenly distributed and may affect a portion of the rock volume in the C-1 and C-4B sub-intervals. Due to the increase in structural clay volume, compaction, and cementation, the porosity, permeability, and productivity of these sub-intervals are reduced. The C-1 is the coarsest grained sub-interval. It is a well-sorted medium-grained sandstone with occasional coarse and very-coarse grains. The C-1 has a fairly uniform thickness of 14 feet to 18 feet except to the southeast where it thins due to truncation. The upper portion of the C-1 sub-interval gradationally fines upward into the C-2 sub- interval. The C-2 sub-interval is the finest grained unit of the Kuparuk C interval and is considered non-reservoir. In the western portion of the Aurora Pool, it is dominated by silty mudstone with occasional very fine-grained sand laminations and interbeds. In the eastern part of th Aurora, the C-2 lithology transitions to very fine-grained muddy-silty sandstone, indicating a lateral facies change from west to east. The C-2 interval has a somewhat uniform thickness of 28 feet to 36 feet in the western part of the field. The C-2 thins to the southeast and is eventually truncated. The C-3A sub-interval is composed of coarsening upward sandstone beds interbedded with silty mudstone. The sandstone beds range from 1 to 2 feet thick, silty, very fine- grain sand at the base up to 10 feet thick, fine-grained sand at the top. The mudstone interbeds display lateral facies variation, similar to the underlying C-2 sub-interval, in that they coarsen eastward to silty very fine-grained sandstone toward the truncation. The overlying C-3B sub-interval is distinguishable from the underlying C-3A sub- Aurora Pool Rules and Area Injection Order 7/23/2001 interval. The sandstones amalgamate and the mudstone interbeds are not present. The C-4A sub-interval continues the coarsening upward trend from fine-grained sandstone at the base to medium-grained sandstone toward the top. Due to the relatively coarse grain size and low volume of clay matrix, the C-4A sub-interval has the highest net to gross and reservoir qualitY in the Kuparuk Formation in the Aurora Pool area. The C-4A and C-4B sub-intervals are separated by an intra-formational unconformity that marks the end of the coarsening upward trend. This unconformity, called the C-4 Unconformity, is a disconformity in the western half of the accumulation. However, it truncates downward through the stratigraphic section in the eastern half of Aurora, where it eventually merges with the Lower Cretaceous Unconformity. The top portion of the C- 4B is a fining upward sequence into the overlying Kalubik Formation. C-4 interval thickness varies due to interaction by unconformities. The interval is thickest at the Beechey Point area where total C-4 thickness exceeds 60 feet. The interval thins southeastward and is eventually truncated. Structure Exhibit 1-2 is a structure map on the top of the Kuparuk Formation with a contour interval of 25 feet. Top Kuparuk structure in the Aurora area is essentially a northwest-southeast oriented ridge, which is broken up by north-south striking faults. Gentle slopes dipping 2.5 to 6.5 degrees away from the structural crest characterize the northeast and southwest flanks of the ridge. In contrast, rotated fault blocks characterize the southern and western flanks of the ridge. 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 well. The southeastern terminus of the Aurora Pool is coincident with the "Prudhoe High", a large basement-involved structural uplift that underlies the Prudhoe Bay field. Early Cretaceous and older sediments lapped over this structural high, and were later uplifted and subsequently beveled off by unconformities. Thus, this major structural high east of the Aurora accumulation is devoid of Kuparuk. The Kuparuk Formation thins 7/40 Aurora Pool Rules and Area Injection Order 7/23/2001 southeastward to a zero edge against the Prudhoe High. The erosional truncation is orthogonal to the northwestern orientation of the overall structural ridge As shown on Exhibit 1-5, Aurora can be divided into five structurally defined areas. (1) The Beechey Block, the westernmost area is a complexly faulted area upthrown to a major north-south fault. The Beechey Point wells were drilled in this area. (2) The V- 200 Block is a structurally stable area between the Beechey Block to the west and the north-south bisecting fault to the east. The V-200 well and the first group of horizontal development wells (S-100, S-101, S-102) penetrate this block. (3) The Crest Block is an intensely faulted area on the upthrown (eastern) side of the north-south bisecting fault. The top of the Kuparuk horizon reaches its structural crest at 6,450 ft. tvdss in the Crest Block. Ten S-Pad Sag River/Ivishak wells have penetrated the Kuparuk Formation in this block. (4) The North of Crest Block lies north of the Crest Block and east of the major north-south fault. The North Kuparuk 26-12-12 and Aurora development wells S- 103, S-104, and S-105 provide well control in this block. (5) The Eastern Block includes the area east of another north-south fault system near the S-08 and S-02 wells. This block is less structurally complex than the Crest Block and includes the southeastern thinning and truncation of the Kuparuk reservoir. Eight S-Pad Sag River/Ivishak wells penetrate the Kuparuk Formation in this block. Exhibit 1-6 is a northwest-southeast oriented structural cross-section along the axis of the Aurora structural ridge (see Exhibit 1-2 for location). This cross-section illustrates the effect of north-south oriented faulting as well as the eastern truncation of the Kuparuk reservoir by the three unconformities. Exhibit 1-7 is a dip-oriented seismic traverse at the same northwest-southeast location as the cross section (see Exhibit 1-2 for location). This exhibit shows the overlying and underlying stratigraphy as well as the fault complexity of the area. Exhibit 1-8 is a strike-oriented seismic traverse from southwest to northeast (see Exhibit I-2 for location). It shows a cross view of the structural ridge that forms the Aurora Pool, and it also illustrates how fault complexity varies at different stratigraphic horizons. 8/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Fluid Contacts Exhibit 1-9 shows the interpreted Oil/Water Contacts (OWCs) and Gas/Oil Contacts (GOCs) in the Aurora Pool. Based on wireline logs, OWCs have been interpreted in the North Kuparuk 26-12-12 well at 6812 feet tvdss and at 6835 feet tvdss in the Beechey Point State #2 well. Repeat Formation Tester (RFT) pressure gradient data in the V-200 well indicate a free water level at 6824 feet tvdss. These data suggest either a 23 feet range of OWC uncertainty or compartmentalization of the Aurora fault blocks and a westward deepening of the OWC across the Aurora area. At present a common GOC for the Aurora Pool has not been identified. Based on wireline logs, core analysis saturations, and core staining, a GOC is interpreted in the S- 16 well at 6631 feet tvdss. Based on well tests, mudlog and wireline logs, a GOC is interpreted in the Beechey Point State #1 well at 6678 feet tvdss. Sidewall core saturations and staining, and RFT pressure gradient data and fluid samples from the S-31 and S-24A wells in the Crest Block indicate oil above the GOC depths in the S-16 and Beechey Point State #1 wells. The Crest Block appears to be gas free. Pool Limits The trap for oil and gas in the Aurora Pool is created by a combination of structural and stratigraphic features. The accumulation is bounded to the west by several faults where the reservoir is juxtaposed against impermeable shales of the overlying Kalubik Formation and HRZ Shale. To the southwest and north, the pool limit is defined by the down-dip intersection of the top of reservoir with the oil-water contact. To the east and southeast the reservoir is truncated by the Pre-Aptian, C-4, and Lower Cretaceous Unconformities. These unconformities merge at the southeastern limit of the field. The boundary of the Aurora PA, including the Expansion Areas, is within the proposed boundary of the Aurora Pool. Exhibits 1-10 through 1-12 are net sandstone maps of the Aurora Pool with a contour interval of 10 feet. Exhibit 1-13 is a net hydrocarbon pore foot map of the Aurora Pool with a contour interval of 10 feet. 9/40 Aurora Pool Rules and Area Injection Order 7/23/2001 II. Reservoir Description and Development Planning Rock and Fluid Properties The reservoir description for the Aurora Pool is developed from the Aurora Log Model. Geolog's Multimin is used as the porosity/lithology 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 lithologic 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 #1, S-04 and S-16. Porosity and Permeability Porosity and permeability measurements were based upon routine core analysis (air permeability with Klinkenberg correction) from the following well set: S-16, S-04, Beechey Point State #1, NWE 1-01, NWE 1-02, and NWE 2-01. The ratio of vertical to horizontal permeability (kv/kh) was 0.006 per 20 feet interval, based on the harmonic average of routine core data. Typical single plug kv/kh ratios ranged from 0.4 to 1.2. Exhibit II-1 shows values for porosity and permeability by zone that were used in the reservoir simulation. Net Pay Net pay was determined from the following criteria: minimum porosity of 15%, Vclay < 28%, and Vglauconite <40%. If the volume of siderite exceeded 30%, the net pay was discounted by a factor of 0.5. Exhibit II-1 shows gross thickness by zone based on marker picks and net pay based on the Aurora Log Model criteria. The 15% porosity cut off corresponds to approximately 1 md of permeability and what could reasonably be expected to be reservoir. Exhibit 11-6 shows a cross plot of porosity vs permeability. 10/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Water Saturation Water saturations for the Aurora reservoir model were derived using mercury injection capillary pressure (MICP) analyses from S-04 and S-16 core. The distribution of the data was characterized using two distinct Leverett J-functions for rock with >20md and <20md permeability. The capillary pressure data were then used to initialize the Aurora reservoir model utilizing initial water saturations as shown in Exhibit Iio 1. Relative Permeability Relative permeability curves for Aurora were derived by comparison to analogs on the North Slope. The crude oil from Aurora was evaluated against other North Slope reservoirs. In terms of API gravity and chemical composition, the Aurora crude most closely resembles Prudhoe Bay and Pt. Mclntyre crude. The Kuparuk sands within the Aurora Pool resemble two Pt. Mclntyre rock sub-types, referred to as rock type #6 (for permeability >20md) and rock type #8 (permeability <20md). The relative permeability curves generated for these Pt. Mclntyre rock types were employed in the Aurora reservoir model. Wettability Based on the relatively light nature of the Aurora crude and relative permeability data from the Pt. Mclntyre analog, the reservoir is expected to be intermediate to water wet. Initial Pressure & Temperature Based on RFT data from V-200, the initial reservoir pressure is estimated at 3433 psia at the reservoir datum of 6700 feet tvdss. The reservoir temperature is approximately 150 degrees Fahrenheit at this datum. Fluid PVT Data Reservoir fluid PVT studies were conducted on V-200 crude from recombined surface test separator samples and RFT downhole samples: The reservoir pressure was 3433 psia at 6700 feet tvdss (datum). The API gravity was 29.1° with a solution gas oil ratio (GOR) of 717 scf/stb. The formation volume factor was 1.345 RVB/STB and the oil 11/40 Aurora Pool Rules and Area Injection Order 7/23/2001 viscosity was 0.722 centipoise at reservoir pressure and temperature. The bubble point for Aurora crude varied according to the sampling method. RFT samples from V-200 had bubble points ranging from 3028 psig to 3590 psig. This dispersion is most likely due to the sampling process. The recombined surface samples had a bubble point of 3073 psig. Exhibit 11-2 shows a summary of the fluid properties for the Aurora accumulation. Exhibit 11-3 contains a listing of PVT properties as a function of pressure. 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. Formation gas in place ranges from 75 to 100 bscf, and gas cap gas ranges from 15 to 75 bscf. Reservoir Performance Well Performance Eight wells have been tested in the Kuparuk formation at Aurora. Five of the test wells (Beechey Point State gl, Beechey Point State #2, North Kuparuk 26-12-12, V-200, and S-24Ai) are unavailable for Aurora production. Six development wells have been completed and tested in the Kuparuk (S-100, S-101, S-102, S-103, S-104 and S-105). The Beechey Point State gl well was tested twice, producing 1.334 mmscfd gas (17.8 bopd condensate) and 5700 mmscfd gas. A GOC pick was not clearly defined, but based on interpreted wireline log and test data the GOC is possibly at 6678 feet tvdss, but could range from 6648 feet tvdss to 6705 feet tvdss. Pressure buildup analysis indicates that the Kuparuk sands were badly damaged with a skin in excess of +50. In Beechey Point State #2, an attempt to test the Kuparuk horizon was made, but the formation would not flow. It is suspected that the Kuparuk sands were badly damaged during drilling based on the high skin from Beechey Point State gl. An OWC is interpreted at 6835 feet tvdss from sidewall core data and logs. IZ/41O Aurora Pool Rules and Area Injection Order 7/23/2001 The North Kupamk 26-12-12 well had three flow tests performed in the Kuparuk. The first produced 8 bbls of oil over 2-6 hours, the second produced 32 bopd, and the third 28 bopd. An OWC was interpreted at 6812 feet tvdss from logs. Oil API gravity ranged from 25.2 to 26.4 degrees. The V-200 encountered oil in the Kuparuk and a free water level was calculated from RFT pressure data at 6824 feet tvdss. The V-200 was tested in four stages while progressively adding perforations uphole. The initial test, with perforations at 6900 - 6920 feet MD, tested at 387 bopd with a GOR of 541 scf/stb. The second production test opened an additional 20 feet of formation (6880-6920 feet MD) and tested at 1517 bopd with a GOR of 535 scf/stb from both intervals. After the second set of perforations was added, surface PVT samples were collected and a pressure transient test was performed. The third production test opened a further 18 feet of formation (6862-6920 feet MD) and tested at 1801 bopd with a GOR of 677 scf/stb from all three intervals. When the well was logged, a final production test flowed at a rate of 1915 bopd with a GOR of 718 scf/stb from all three intervals. The S-24Ai well was not flow tested, but RFT data were collected. The entire Kuparuk interval was oil bearing and no gas or water contact was detected. The RFT pressures and oil gradient were sufficiently different (11 psi at common tvdss) from V-200 to suggest that the S-24Ai fault block is isolated from the V-200 fault block. The API gravity of the RFT sample was 25.6 degrees. S-100 was drilled as a horizontal well in the V-200 fault block in Phase I of Aurora development drilling. Log analysis indicates S-100 has over 1500 feet of net pay. The well was brought on line in November 2000 and the initial well test produced 7,230 bopd at a GOR of 831 scf/stb. Initial AP1 gravity was 26°. S-101 was drilled as a horizontal well in the southern portion of the V-200 fault block as the second well of Phase I development drilling. Log analysis indicates the well has over 2500 feet of net pay. A December 2000 production test produced 1062 bopd at a GOR of 20707 scf/stb. Well logs suggest a possible GOC in the toe of the well at ~6680 feet 1 DI ~U Aurora Pool Rules and Area Injection Order 7/23/2001 tvdss. Initial API gravity was 47°. The elevated API was due to the production of gas condensate liquids. S-102 was drilled as a horizontal well in the northern portion of the V-200 fault block as the third well of Phase I development drilling. Log analysis indicates that the well has approximately 400 feet of net pay and that the reservoir is of considerably lower quality than for the S-100 and S-101 wells. A December 2000 test produced 458 bopd at a GOR of 12005 scf/stb. Initial AP1 gravity was 26°. Aquifer Influx The aquifer to the north of Aurora could provide pressure support during field development. Early production data from the flanks of the field will be evaluated to determine the extent of pressure support. Current modeling efforts, both with and without a Fetkovich aquifer, do not significantly change injector requirements or location. As production data become available this assessment could change. Gas Coning / Under-Running Log and RFT data were integrated with the Aurora structure map to identify free gas in the Aurora Pool. It is likely that there are three to five small discrete gas caps located throughout the accumulation. Beechey Point State #1 logs suggest a GOC at 6678 feet tvdss in the western portion of the Aurora Pool. Sidewall core from S-31 and RFT fluid samples from S-24Ai in the central portion of the accumulation suggest that this fault block is filled with oil to the crest of the structure. Log and core data from S-16 indicate the Eastern Block may have a GOC at 6631 feet tvdss. Initial production from development wells may produce gas cap gas through coning or under-run mechanisms. This gas volume could impact early well performance, but the effect should dissipate as the small gas caps are produced and pressure maintenance is initiated. The current depletion plan is to produce any associated gas, while evaluating well work options. As production and reservoir surveillance data become available, this interpretation could alter substantially. 14/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Development Planning A reservoir model of the Aurora Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. Reservoir Model Construction A fine scale three-dimensional geologic model of Aurora was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk reservoir volume and distribution of porosity for the Aurora reservoir model. This reservoir model is a three-dimensional, three-phase, black oil simulator. The model area encompasses the known extent of the Aurora accumulation. The model has 300 feet by 300 feet (2.0 acre) cells. The reservoir model is defined vertically with five layers that have a nominal thickness of five to 20 feet. Exhibit II-1 shows the correspondence of model layers to geologic zones and summarizes average physical properties for each model layer. Faults and juxtaposition are honored in the model through the use of corner point geometry and non-local grid connections. Water saturations in the reservoir model were established by capillary pressure equilibrium. Two Leverett J-Curves were used for >20md and <20md rock. Oil water contacts were varied across the field from 6812 feet to 6835 feet tvdss based on available data (log, RFT, etc.) from each fault block. The reservoir pressure was set to 3433 psia at the datum of 6700 feet tvdss. Model Results Two,development options were evaluated for Aurora: primary depletion and waterflood. Primary Recovery The primary recovery mechanism was a combination of solution gas drive, gas cap expansion, and aquifer support. Model results indicate that primary depletion would recover approximately 12% of the OOIP. Exhibit 11-4 shows production and recovery profiles for primary depletion. Under primary depletion, the Aurora Pool experiences a rapid decline in reservoir pressure that falls below 2000 psig by year 2006. Production 15/40 Aurora Pool Rules and Area Injection Order 7/23/2001 rate peaks at 7000 to 9000 bopd. Waterflood Waterflood has been identified as the preferred development option for Aurora. It is anticipated that field development will require ten to thirteen producers and five to seven injectors. The reservoir simulation of waterflood reached a recovery of 34% of the OOIP with 0.50 hydrocarbon pore volume injected (HCPVI). Exhibit 11-5 shows production and recovery profiles for an Aurora waterflood development. Production rate peaks at 14,000 - 17,000 bopd with a maximum water injection rate of 20,000 - 30,000 bwpd. Enhanced Oil Recovery (EOR) Preliminary analysis indicates the potential for miscible gas flood in the Aurora accumulation. Early screening indicates on the order of 5% incremental oil recovery. Further evaluations need to be performed to determine the impact on total recovery. Development Plans Phase I Development Phase 1 development focuses on the V-200 Block and North of Crest Block. Several waterflood development options were studied using the Aurora reservoir simulator. Initial studies focused on the V-200 fault block to optimize well location and producer/injector placement. The base development consists of three horizontal wells to develop and further evaluate the V-200 Block (S-100, S-101, S-102). Development drilling data indicates the presence of a gas cap at a log-interpreted depth of ~6680 feet tvdss. Simulation studies indicate recovery from the V-200 block can be optimized by converting S-101 to injection and the potential for additional injection wells. Recovery in this development block was estimated to reach 31% of the oil initially in place. S-101 will be converted to injection in the second quarter of 2001. Several bottom hole locations were evaluated for the North of Crest development. The optimal configuration was determined to be a three well development with a pre- produced injector. The North of Crest development will use vertical fracture stimulated wells to access both the C and A sands. A vertical well provides access to both sands 16/40 Aurora Pool Rules and Area Injection Order 7/23/2001 while avoiding complications with faults that could hinder horizontal wells in this portion of the field. A GOC in this section of the field may be encountered at 6631 feet tvdss based on offset wells. Ultimate recovery is estimated to be approximately 35% in this area of the pool. Phase II Development Phase II of Aurora development is expected to involve six to eight producers and three to four injectors. Locations and spacing will be dependent on further reservoir simulation and evaluation of production data from Phase I development. The phased drilling program will target portions of the reservoir in the crest, along the eastern flank, and in the Beechey Block area. An approximate six well drilling program is expected to commence in 2001 that will determine additional well placements for completion of Phase II development. Well Spacing The V-200 fault block will utilize horizontal wells initially spaced at 480 acres in irregular patterns. Further infill drilling will be evaluated based on production performance and surveillance data. In the North of Crest, the Phase I vertical well spacing is expected to be approximately 120 acres per well. Infill drilling or peripheral drilling may be justified at some point of development. To allow for flexibility in developing the Aurora Pool, a minimum well spacing of 80 acres is requested. Reservoir Management Strategy Pressure support prior to waterflood start-up will be provided from aquifer support and a gas cap, where present. Once water injection begins, the voidage replacement ratio (VRR) will exceed 1.0 to restore reservoir pressure. Once the reservoir pressure has been restored, a balanced VRR will be maintained for pressure support. The objective of the Aurora reservoir management strategy is to operate the field in a manner that will achieve the maximum ultimate recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached 17/40 Aurora Pool Rules and Area Injection Order 7/23/2001 as a dynamic process. The initial strategy is derived from model studies and limited well test information. Development well results and reservoir surveillance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Aurora Pool will continue to be evaluated throughout reservoir life. Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Aurora Pool. Development will take place in two distinct phases. The first phase will use three horizontal wells to develop the V-200 Block and three vertical wells to develop the North of Crest area. Phase II will develop the remainder of the field. Peak production rates are expected to be 14,000 - 17,000 bopd. Upon waterflooding commencement, peak injection rates will be 20,000 - 30,000 bwpd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. 18/40 Aurora Pool Rules and Area Injection Order 7/23/2001 III. Facilities General Overview Aurora wells will be drilled from an existing IPA drill site, S-Pad, and will utilize existing IPA pad facilities and pipelines to produce Aurora reservoir fluids to Gathering Center 2 (GC2) for processing and shipment to Pump Station No.1 (PS1). Aurora fluids will be 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. The GC2 production facilities to be used include separating and processing equipment, inlet manifold and related piping, flare system, and on-site water disposal. IPA field facilities that will be used include a 24" low-pressure large diameter flowline, a 10" gas lift supply line, and a 14" water injection supply line. An 8" MI supply line from GC2 to S-Pad could be utilized for future EOR applications. The oil sales line from GC2 to PS ! and the power distribution and generation facilities will be utilized. Exhibit III-1 is a flow diagram of the proposed Aurora Facilities at S-Pad and Exhibit III-2 is an area map showing locations of the pad facilities that will be used for Aurora development. Drill Sites, Pads, and Roads S-Pad has been chosen for the surface location of Aurora wells to reach the expected extent of the reservoir while minimizing new gravel placement, minimizing well step out and allowing the use of existing facilities. Wells will primarily be drilled west and north of the existing IPA wells. An expansion of the existing pad size to accommodate additional wells at S-pad was completed in April, 2000. A schematic of the drill site layout is shown in Exhibit III-2. No new pipelines are planned for development of the Aurora reservoir. Aurora production will be routed to GC2 via the existing S-Pad low-pressure large diameter flowline. No new roads or roadwork will be required. 19/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Pad Facilities and Operations A trunk and lateral production manifold capable of accommodating up to 20 new Aurora wells will be built as an extension to an existing S-Pad manifold system. A schematic showing the surface well tie-ins is shown in Exhibit 111-2. Water for waterflood operations will be obtained from an extension to an existing 6" water injection supply line at S-Pad. Preliminary estimates indicate the line is sufficient to deliver water to Aurora injection wells at a rate of 28,000 bpd and a pressure of approximately 2000 - 2100 psig. Should current water injection pressures be insufficient, injection pressure can be boosted locally. An upgrade of the existing S-Pad power system should not be necessary for additional water injection booster pumps. Artificial lift gas will be obtained from the existing 10" gas lift supply line at S-Pad. Preliminary estimates indicate that the line is sufficient to deliver gas to Aurora production wells at a rate of 30 mmscfd and a pressure of approximately 1800 psig. All well control will be performed manually by a pad operator. Exceptions to this are the automatic well safety systems and the pad emergency shutdown system that can be triggered either manually or automatically. Production allocation is addressed in Section V. Production allocation for the Aurora reservoir currently is based upon the Interim Metering Plan (approved November 15, 2000). The plan requires a minimum of two well tests per month through the S-Pad test separator for each Aurora well. Daily production is based on straight-line interpolation between valid well tests. The total volume of production from the Aurora reservoir is designated an allocation factor of 1.0. Well pad data gathering will be performed both manually and automatically. The data gathering system (SCADA) will be expanded to accommodate the Aurora wells and drill site equipment. The SCADA system will continuously monitor the flowing status, pressures, and temperature of the producing wells. These data will be under the well pad operator's supervision through his monitoring station. 20/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Production Center No modifications to the GC2 production center will be required to process Aurora production. GC2 was built to process a nominal oil rate of 400 mbopd, gas rate of 320 mmscfd (modifications have increased this to 1,200 mmscfd) and a nominal produced water rate of 280 mbwpd. Production, including that from the Aurora Reservoir, is not expected to exceed existing GC2 capacity. 21/40 Aurora Pool Rules and Area Injection Order 7/23/2001 IV. Well Operations Drilling and Well Design A number of wells have been drilled into the Aurora accumulation. Several exploration wells were drilled approximately 30 years ago. However, only the recently drilled S-100, S- 101, S- 102, S- 103, S- 104, and S- 105 are currently completed in the Kuparuk Formation. Many Prudhoe Bay Unit wells were logged across the Kuparuk Formation while drilling to the Ivishak Formation. However, until recently, the Kupamk Formation was not definitively tested. In February 1999, the Aurora V-200 appraisal well was drilled off an ice pad and tested at 1900 bopd. After proving the commerciality of the Aurora Oil Pool, the V-200 well was plugged and abandoned with plans to develop the Aurora Oil Pool using existing facilities at S-Pad. More recently, the PBU Ivishak S- 24Ai well was logged and a fluid sample in the Kuparuk obtained in May 1999. The S- 24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. At the present time the Aurora accumulation is being produced under Tract Operations from three wells completed in the Kuparuk Formation. Three additional wells have been drilled and will be completed shortly. Approximately fifteen (15) to nineteen (20) production and injection are forecasted for the Aurora development. Aurora development wells will be directionally drilled from S-Pad utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in other North Slope fields. A 20-inch conductor casing will be set 80 feet below pad level and cemented to surface. Consideration will be given to driving or jetting the 20-inch conductor as an alternative setting method. A diverter system meeting AOGCC requirements will be installed on the conductor. Surface hole would be drilled no shallower than 2300 ft. tvdss. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle-build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous PBU wells. Cementing and casing requirements similar to other North Slope fields have been been adopted for Aurora. 22/40 Aurora Pool Rules and Area Injection Order 7/23/2001 The casing head and a blowout-preventer stack will be installed onto the surface casing and tested consistent with AOGCC requirements. The production hole will be drilled below surface casing to the Kupamk Formation, allowing sufficient rathole to facilitate logging. Production casing will be set and cemented. Production liners will be used as needed, to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells, such as high departure wells. To date, no significant H2S has been detected in the Kuparuk Formation while drilling PBU wells nor in any Aurora wells drilled to-date. However, with planned waterflood operations, there is potential of generating H2S over the life of the field. Consequently, H2S gas drilling practices will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellsite. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. Well Design and Completions Both horizontal and vertical wells are anticipated at Aurora. The horizontal well completions could be perforated casing, slotted liner, or a combination of both. All vertical wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8 to 5-1/2 inches, depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Aurora wells. 23/40 Aurora Pool Rules and Area Injection Order 7/23/2001 The following table indicates casing and tubing sizes for proposed Aurora well designs. Surface Inter / Prod Casing Production Production Casing Liner Tubing Vertical 12-1/4" to 7" 9-5/8" to 4-1/2" 5-1/2" to 2-7/8" 5-1/2" to 2-3/8" Horizontal 12-1/4" to 7" 9-5/8" to 4-1/2" 5-1/2" to 2-7/8" 5-1/2" to 2-3/8" Plans are to run L-80 casing in the Aurora wells. Tubing strings will be completed with either 13-Cr 9-Cr/1Moly, or with L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/1Moly, which is compatible with both L-80 and 13-Cr. Proposed wells will be completed in a single zone (Kuparuk Formation), or multi-zone (Kuparuk and Schrader Bluff, or Kuparuk and Sag/Ivishak) utilizing a single string and multiple packers as necessary. As shown in the typical well schematics, Exhibit IV-1 for a vertical well and Exhibit IV-2 for a horizontal well, and Exhibit IV-3 for a multi-zone well, the wells have gas lift mandrels to provide flexibility for artificial lift or commingled production and injection. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Any completions which vary from those specified in State regulations will be brought before the commission on a case by case basis. The Aurora Owners may utilize surPlus IPA wells for development, provided they meet Aurora needs and contain adequate cement integrity. Initial Development The Aurora depletion plan consists of drilling six development wells under Phase I development. The S-100, S-101i and S-102 wells, an injector and two producers, are horizontal completions drilled on the west side of the N-S trending fault (V-200 Fault Block Area). Three other wells, S-103, S-104i and S-105, a multi-zone injector and two producers, are vertical completions drilled in the North of Crest area on the east side of the N-S trending fault. Injectors are being pre-produced prior to converting to permanent 24/40 Aurora Pool Rules and Area Injection Order 7/2312001 injection. Production from these wells will be used to evaluate the reservoir's productivity and pressure response, enabling refinement of current reservoir models and depletion plans. Current modeling suggests that the V-200 Block pre-produced injection well can be converted to injection service after six months to twelve months of primary production without jeopardizing ultimate recovery in the V-200 Block. A structure map showing the V-200 Block is shown in Exhibit 1-2. In the S-100, S-101i and S-102 Phase I development wells, LWD/MWD logging was conducted after top setting the 7" intermediate casing. Plans are to set the 7" intermediate casing in the top 10-50 ft. MD (0-30 feet sstvd) of the Kuparuk Formation. The MWD will include measurement of drilling parameters such as weight on bit, rate of penetration, inclination angle, etc. LWD will include GR/Resistivity and Density and Neutron porosity throughout the build and horizontal sections. A 10-11 ppg freshwater low-solids non-dispersed mud system or equivalent will be used to drill the production hole down to the 7" casing point. The mud system parameters will be optimized to minimize mud filtrate loss before drilling the 6-1/8" horizontal section. After drilling the 6-1/8" horizontal hole, a 4-1/2" slotted or solid liner will be run, cemented and perforated as necessary Subsurface Safety Valves There is no requirement for subsurface safety valves (SSSVs) in Aurora wells under the applicable regulation, 20 AAC 25.265. Moreover, in light of developments in oil field technology and controls and experience in operating in the arctic environment, the Commission has eliminated blanket SSSV requirements from both rules governing both the Prudhoe Oil Pool and the Kuparuk River Oil Pool. See Conservation Orders 363 and 348, respectively. However, Rule 5 of Conservation Order 98A appears to require subsurface safety valves for Aurora wells. Therefore, the applicants recommend removal of the Aurora Oil Pool 25/40 Aurora Pool Rules and Area Injection Order 712312001 from its scope. operations. Removing the SSSV requirement would be consistent with other PBU Existing completions are equipped with SSSV nipples, should the need arise to install subsurface storm chokes or pressure operated safety valves for future MI service. Surface Safety Valves Surface safety valves are included in the wellhead equipment. These devices can be activated by high and low pressure sensing equipment and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded. Testing of SSVs will be in accordance with AOGCC requirements. Drilling Fluids In order to minimize skin damage from drilling and to maintain shale stability, water- based KC1 mud may be used to drill through the Kuparuk Formation at Aurora. Freshwater low solids, non-dispersed fluids will be used to drill upper sections of each well. Stimulation Methods Stimulation to enhance production or injection capability is an option for Aurora wells. There was evidence of formation damage caused by drilling and completion fluids in the V~200 well. Consequently, the need for fracture stimulation is possible. It may also be necessary to stimulate the horizontal wells, depending upon well performance. Reservoir Surveillance Program Reservoir surveillance data will be collected to monitor reservoir performance and define reservoir properties. I Most of the area governed originally by CO 98A was removed in 1981, when Conservation Order 173, the Kuparuk River Field, Kuparuk River Oil Pool Rules were adopted. 20/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Reservoir Pressure Measurements An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 6,700 ft. tvdss. An initial static reservoir pressure will be measured prior to production in at least one well for each fault block. Additionally, a minimum of two pressure surveys will be obtained annually for the Aurora accumulation, one on the east side and one on the west side of the N-S dividing fault. These will consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. It is anticipated that the operator will collect more than two pressure measurements per year during initial field development due to field complexity and fewer as the development matures. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, may be periodically run to help determine reservoir performance (i.e., production profile and injection profile evaluations). Surveillance logs will be run on multi-zone completions to assist in the allocation of flow splits as necessary. 27/40 Aurora Pool Rules and Area Injection Order 7/23/2001 V. Production Allocation Aurora production allocation will be done according to the PBU Western Satellite Production Metering Plan. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor will be applied to adjust the total Aurora production. A minimum of two well tests per month will be used to tune the performance curves, and to verify system performance. No NGLs will be allocated to Aurora. To support implementation of this procedure, several improvements to the WOA allocation system have been initiated. Conversion of all well test separators in the GC-2 area to two-phase operation with a coriolis meter on the liquid leg is expected to be completed mid-2001. The test bank meters at GC-1 and GC-2 have been upgraded as part of the leak detection system and a methodology for generating and checking performance curves for each well has been developed. Modifications to the automation system are expected to be completed mid-2001. Until the upgraded metering and allocation system for the WOA is ready for implementation, Aurora wells will use an interim metering and allocation plan based on a minimum of two well tests per month with linear interpolation and a fixed allocation factor of 1.0. We request Commission approval under 20 AAC 25.215(a) that the Aurora metering either exceeds the requirement for monthly well tests or is an acceptable alternative. .' 28/40 Aurora Pool Rules and Area Injection Order 7/23/2001 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection to enhance recovery from the Aurora Oil Pool. This section addresses the specific requirements of 20 AAC 25.402(c). Plat of Project Area 20 AAC 25.402(c)(1) Exhibit 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Aurora Oil Pool as of April 1, 2001. 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, or any applicable successor regulation. Operators/Surface Owners 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) BP Exploration (Alaska) Inc. is the designated operator of the Aurora Participating Area. Surface Owners within a one-quarter mile radius and inclusive of the Aurora Participating Area are as followings: State of Alaska Department of Natural Resources Attn: Dr. Mark Myers P.O. Box 107034 Anchorage, AK 99510 Pursuant to 20 AAC 25.402(c)(3), Exhibit V-1 is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area of and included within the Aurora Participated Area have been provided a copy of this application for injection. Description of Operation 20 AAC 25.402(c)(4) Development plans for the Aurora Oil Pool are described in Section II of this application. 29/40 Aurora Pool Rules and Area Injection Order 7123/2001 Drillsite facilities and operations are described in Section III. Geologic Information 20 AAC 25.402(c)(6) The Geology of the Aurora Oil Pool is described in Section I of this application. Injection Well Casing Information 20 AAC 25.402(c)(8) The S-101 well and S-104i well will be converted to injection service for the Aurora Oil Pool Enhanced Recovery Project. The casing program for wells S-101 and S-104i was permitted and completed in accordance with 20 AAC 25.030. Exhibit IV-2 and IV-3 details the completion for the S-101 well and the S-104i well respectively. A cement bond log indicates good cementbond 'acro~ss and above the Kuparuk River Formation in S-104i; whereas further logging will be necessary to confirm cement integrity in S-101. Conversion of the S-101 well and the S-104i well will be conducted in accordance with 20 AAC 25.412. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. All drilling and production operations will follow approved operating practices regarding the presence of H2S in accordance with 20 AAC 25.065. Injection Fluids 20 AAC 25.402(c)(9) Type of Fluid/Source The Aurora Enhanced Recovery Project will utilize GC2 produced water as the water source. 30/413 Aurora Pool Rules and Area Injection Order 7/23/2001 Composition The composition of produced water from GC2 and the Aurora Oil Pool is shown in Exhibits VI-4. The composition of Aurora produced water will be a mixture of connate water and injection water. Maximum Injected Rate Maximum water injection requirements at Aurora Oil Pool are estimated at 20,000 to 30,000 BWPD. Compatibility with Formation and Confining Zones Core, log and pressure-buildup analysis indicate no significant problems with clay swelling or compatibility with in-sim fluids. Analysis of the S-104i 'core indicates relatively low clay content (5-35% by volume), primarily in the form of illite. Petrographic modal analysis indicates that clay volumes in the better quality sand sections (>20 md) are in the range of 3 - 6%. Clay volumes increase to approximately 6 - 12% in the rocks with permeabilities in the range of 10 - 20 md. Below 10 md clay volumes increase to a range of 12 - 20%. Most of the identified clay is present as intergranular matrix and is detrital in origin, having been intermixed with the sand through burrowing. The level of clay diagenesis is uncertain at this time, but is expected to include some. grain coating illite. The overall clay composition is believed to. be mostly illitic. No diagenetic kaolinite or chlorite was reported during petrographic analysis. Illitic clays are susceptible to damage in contact with low ionic strength (i.e. fresh) filtrates and treatment fluids. The damaged clays often become dispersed and are therefore potentially migratory with fluid movement. Fluids with ionic strength (salinity) equal to 2% KC1 or greater should not pose a significant risk for damage. Further, the better quality rock types will have the least amount of clay and take most of the introduced fluids. As such, no significant clay-related formation damage is anticipated as long as adequate salinity is maintained. 31/40 Aurora Pool Rules and Area Injection Order 7/23/2001 The presence of iron-bearing minerals suggests that the use of strong acids should be avoided in breakdown treatments, spacers, etc. Geochemical modeling results indicate that a combination of GC2 produced water and connate water is likely to form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Scale precipitation will be controlled using scale inhibition methods similar to those used at Kuparuk River Unit and Milne Point. Injection Pressures 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 1800 psig. The estimated maximum surface. injection pressure for the Aurora Oil' Pool 'Enhaffced Recovery Project is 3000 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing, with a maximum expected bottom hole pressure of 6000 psig. Fracture Information 20 AAC 25.402(c)(11) The expected maximum injection pressure for the Aurora Oil Pool Enhanced Recovery Project wells will not initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. There is no evidence of injection out of zone for similar Kuparuk River Formation waterflood operations on the North Slope. Freshwater Strata There are no freshwater strata in the area of issue (see Section N of the Application for Modification to Area Injection Order No. 4, dated April 5, 1993). Additionally, calculations of water salinity from open hole resistivity logs acquired in the Prudhoe Bay E-16 indicate a salinity range of 40,000 to 45,000 ppm for Cretaceous and Tertiary sands above the Kuparuk River Formation. Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with 32/40 Aurora Pool Rules and Area Injection Order 712312001 freshwater strata. Enhanced Recovery Water injection operations at the Aurora Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Fracture propagation models confirm that injection above the parting pressure will not exceed the integrity of the confining zone. The Kuparuk River Formation at the Aurora Oil Pool is overlain by the Kalubik and HRZ shales, which have a combined thickness of approximately 110 feet. The HRZ is a thick shale sequence, which tends to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones of the Kuparuk River Formation. Mechanical properties determined from log and core data for the HRZ and~Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. A leakoff test was conducted in well S-101 to determine the formation breakdown pressure at the Aurora Oil Pool and that test suggested a fracture gradient of 0.73 psi/ft at initial reservoir conditions. This data agrees with data from offset fields containing wells completed in the Kuparuk River Formation. The Kuparuk River Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of approximately 0.85 psi/ft. In addition, rock mechanics calculations and data from the Prudhoe Bay Oil Pool indicate that sandstone fracture gradients are reduced during waterflooding operations due to reduced in-situ rock stress associated with the injection of water that is colder than the reservoir. Produced water from GC2 would have limited impact on the fracture gradient because the water temperature would be close to the reservoir temperature. 33/40 Aurora Pool Rules and Area Injection Order 7/23/2001 Hydrocarbon Recovery 20 AAC 25.402(c)(14) The Aurora Oil Pool is estimated to have original oil in place of 110 to 146 MMSTB. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15 to 25% of the original oil in place, relative to primary depletion. 34/40 Aurora Pool Rules and Area Injection Order 7/23/2001 VII. Proposed Aurora Oil Pool Rules BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that the Commission repeal Conservation Order 98A or remove the Aurora Oil Pool from its scope and adopt the following Pool Rules for the Aurora Oil Pool: Subject to the rules below and statewide requirements, production from the Aurora Oil Pool, as herein defined, may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. Rule 1: Field and Pool Name The field is the Prudhoe Bay Field and the pool is the Aurora Pool. The Aurora Pool is classified as an Oil Pool. Rule 2: Pool Definition The Aurora Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 6858.5 and 7253.5 feet in the PBU V-200 well within the following area: Umiat Meridian TllN-R12E: Sec 3:Nl/2 T12N-R12E: Sec 17: S1/2; Sec 18: SEll4; Sec 19: El/2; Sec 20: All; Sec 21: All; Sec 22: W1/2NWI/4,SI/2; Sec 23: SW1/4; Sec 25: SWI/4; Sec 26- 28: All; Sec 29: NI/2,SEi/4; Sec 32: El/2; Sec 33 - 35: All; Sec 36: NI/2,SWI/4 Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer to 500 feet to an external boundary where ownership changes. Rule 4: Automatic Shut-In Equipment (a) All wells will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a fail-safe automatic surface safety valve. (c) Surface safety valves will be tested in accordance with Commission requirements. Rule 5: Common Production Facilities and Surface Commingling (a) The PBU Western Satellite Metering Plan satisfies the well testing requirements of 20 AAC 25.230 and 20 AAC 25.275. (b) Each producing Aurora well will be tested and production will be allocated in accordance with the Prudhoe Bay Unit Western Satellite Metering Plan. 35/40 Aurora Pool Rules and Area Injection Order 7/23/2001 (c) (d) Allocated production for Aurora will be adjusted in conjunction with the GC-2 allocation factors. Until the Prudhoe Bay Unit Western Satellite Metering Plan is implemented, the operator shall submit monthly reports containing daily allocation and well test data for agency surveillance and evaluation. During this period, each producing Aurora well will be tested a minimum of two times per month with production allocated by straight-line interpolation between well tests. The Aurora allocation factor will be 1.0 Rule 6: Reservoir Pressure Monitoring (a) A minimum of two pressure surveys will be taken annually for the Aurora Pool. (b) The reservoir pressure datum will be 6700 feet true vertical depth subsea. (c) Pressure surveys may consist of stabilized static pressure measurements at bottom- hole or extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. (d) Data and results from pressure surveys shall be reported annually. (e) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. ~. Rule 7: Gas-Oil Ratio Exemption Wells producing from the Aurora Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 8: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 2500 psi at the datum or within eighteen months of initial production. Rule 9: Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: 1. Summary of produced and injected fluids. 2. Summary of reservoir pressure analyses within the pool. 3. Results of well allocation and test evaluation for Rule 7 and any other special monitoring. 4. Future development plan. The report will be submitted to the state by April 1st each year. Rule 10: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Aurora Pool Rules and Area Injection Order 7/23/2001 VIII. Area Injection Application BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Aurora Pool and consider the following rules to govern such activity: Affected Area: TllN-R12E: Sec 3:N1/2 T12N-R12E: Sec 17: S1/2; Sec 18: SE1/4; Sec 19: El/2; Sec 20: All; Sec 21: All; Sec 22: W1/2NW1/4,S1/2; Sec 23: SW1/4; Sec 25: SW1/4; Sec 26 - 28: All; Sec 29: N1/2,SE1/4; Sec 32: El/2; Sec 33 - 35: All; Sec 36: N1/2,SW1/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids appropriate for enhanced oil recovery may, be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to, and correlate with, the interval between the measured depths of 6858 and 7252 feet in the PBU V-200 well. Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been 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. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 6 below. Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity 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. A test surface pressure of 1500 psi or 0.25 psi/ft, multiplied 37/40 Aurora Pool Rules and Area Injection Order 7/23/2001 by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength will be used. The test pressure must show a stabilizing trend and must not decline more than 10% in a thirty-minute period. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever operating pressure observations, injection rates, or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. MI injectors which fail an integrity test will be SI and secured as soon as possible. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Notification The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State of Federal agency remain the Operators' responsibility. Rule 9: Administrative Action Upon proper application, the Commission. may administratively waive the requirements of any rule stated above 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 an increased risk of fluid movement into an underground source of drinking water (USDW). Aurora Pool Rules and Area Injection Order 7/23/2001 IX. List of EXhibits I-1 1-2 1-3 1-4 1-5 1-6 1-7 1-8 1-9 1-10 1-11 1-12 1-13 II-1 11-2 11-3 11-4 11-5 11-6 III- 1 111-2 IV-1 IV-2 IV-3 IV -4 V-1 VI-1 VI-2 VI-3 Aurora Pool Location Map Top Structure Map Aurora Participating Area (APA) Type Log for Aurora Pool Aurora Areas Structural Cross Section Dip Seismic Cross Section Strike Seismic Cross Section Fluid Contacts Net C4/C3B Sand Map Net C3A/C 1 Sand Map Net A Sand Map Net Hydrocarbon Pore Foot Map Model Layering and Properties Aurora Fluid Properties PVT Properties Production and RecOvery Profiles for Primary Depletion Production and Recovery Profiles for Water Injection Porosity vs Permeability Aurora Well Tie-ins - Northern S-Pad Aurora Facility Location Typical Vertical Completion Typical Horizontal Completion Schrader-Kuparuk Injection Well Aurora and GC2 Water Properties Affidavit Borealis NOPF C4B Sands Borealis NOPF C4A/C3B Sands Borealis NOPF C3A Sands 39/40 Aurora Pool Rules and Area Injection Order 7/23/2001 VI-4 VI-5 VI-6 VI-7 VI-8 VI-9 VII-1 Borealis NOPF C 1 Sands Borealis NOPF A5 Sands Aurora and Borealis C-Sand RFT Data API Gravity and GOR for V-100 and V-200 API Gravity Interpreted Fluid Contacts in the Borealis Region Draft: Prudhoe Bay Unit Western Satellite Production Metering Plan Exhibit I-1: Aurora Pool Location Map SANDPIPER UNIT Mli,,NE~ POINT UNIT COLVILLE RIVER UNIT r!.- J !. "~ j ' \ ~ '~'>-"~-, l* ~ORTHSTAR.~ UNIT t I I ~ ~, ~"~ ~' ! ~ ~uPA~u~VEaUN~ ~UaHO~ 1 i - I I i 0 5 10 15 Miles ~ ~_ .......... ! .................... i BPXA Carto~ra:~hv/4-12-2001/lml 4369 .don Exhibit I-2: Top Structure Map Top C Sond C)epth Mop ) EXHIBIT I-3 AURORA PARTICIPATING AREA (APA) ADL 18 rib / 28254 i =,~=7..- m I 28255 I 16 I I 19 20 I I Expansion I Exp I Area 4 Area 3 I 29,.,! 28259 ~ Expansion I Area 2 28 ADL,28253 15 ADLi 28256 22 27 APA 28258 AD[. 385193 .AD[, 47448 ,.... ,, ;' ,.- .,. , · .,,~ ..,, ... '".. o. ,. ,... · ~, ,,.', ,,, .. ~ ,.:, ,.. ~.l~-..,~, ,; ,. ,~'T. ,, , . ,.,...._~, .. ~.,,..., .~.I~-';.~;~¥ · '.', .~, ~.1 ,.~.,. :., ~ . 23 26 25 --I ~257 I Expansion T12N-R12E Area 1 35 36 r'- 4.7450 ADL 28261 T11N-R12E ADL 28260 Exhibit I-5' Aurora Areas Beechey Block North of Crest Block Eastern Block \ Exhibit I-6: Structural Cross Section A Exhibit I-7' Dip Seismic Section ~ech6y Pt # V200 SO:3 9-~6 S-14 M-I3 A~ Btuff Kuparuk B Exhibit I-8: Strike Seismic Section 8,~ ~ K~p 26- g~ Kuparuk Exhibit I-9: Fluid Contacts Contact Beechey Block V-200 Block Crestal Block GOC 6678' tvdss Per 6631' tvdss (Beechey Pt St #1) Beechey Block (S-16) WOC 6835' tvdss 6824' tvdss 6812' tvdss (Beechey Pt St #2) (V-200) (N Kup 26-12-12) Exhibit 1-10: Net C4/C3B Sand Map Exhibit I-11' Net C3A/Ci Sand Map RURORR FIELD / KUPRRUK C3A+C1 Exhibit 1-12: Net A Sand Map AUrOrA FIELD I KUPRRUK A Exhibit I-13: Net Hydrocarbon Pore Foot Map / PBU Bo~ PA ~jBoundary Exhibit II-1: Model Layering and Properties Average Properties by Simulation Layer Layer Zone Porosity lgermeability Gross -Net Pay Initial (%) (md) Thickness (ft) Water Sat (ft) (%) *3 *3 *1 *2 *2 1 , C4B 21 59 13 4 45 2 C4A 25 158 24 22 30 3 C3B 19 12 21 18 36 4 !C1 19 42 15 7 60 5 A5 16 29 20 9 66 * 1 Based upon stratigraphic formation marker picks. *2 Based upon Aurora Log Model. *3 Based on routine core data. Exhibit II-2: Aurora Fluid Properties VL/oo t:::'¢'r Initial Reservoir Pressure at 6700' tvdss Bubble Point Pressure Reservoir Temperature Oil Gravity Reservoir Oil Viscosity Reservoir Water Viscosity Reservoir Gas Viscosity Solution Gas/Oil Ratio (Rs) Oil Formation Volume Factor (Bo) Water Formation Volume Factor (Bw) Gas Formation Volume Factor (Bg) 3433 psia 3433 psia 150° F 25°- 30°API _......~,-r_.~~..u....t,.hl~¢ 0.722 cp 0.45 cp 0.022 cp 717 SCF/STB 1.345 RBL/STB 1.03 RBL/STB 0.843 RBL/MSCF Exhibit II-3: PVT Properties Pressure ..... BO ..... i Bg .......... OiI ............. ~S ......... S°lutio.n ........ !~s,!g ............ R~$~B ,Rbl/m~s.cf ~i~,o.s..it~..~Visc.osi~y ............ ~R ....... cp cp scf/STB 3464 1.345 0.722, 717 ......... 3i'00 113i.6 .......... 018'43 0.744 01022 6'44 ~ , 2750 1.289 0.945 0.789 0.020 575 2400 1.262 1.083 0.858 0.019' 508 2050 1.236 1.275 0.958 0.017' 441 1700 1.210 1.554 1.100 0.016 375 1350 1.185 1.987 1.280 0.015 309 1000 1.159 2.732 1.530 0.014 244 650 1.133 4.283 1.880 0.013 177 300 1.102 9.340 2.440 0.012 105 124 1.081 21.615 2.950 0.011 61 0 1.041 4.520 0 Exh[bff II-4: Production and Recovery Profi]es for Primary Depletion 2,000 1,000 0il Producti(m I --~- sciYstb i 2000 2005 20! 0 2015 2020 2025 2030 20,000 1S,O00 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,0O0 9(X) Water Production 800 700 6OO 500 400 30O 20O I O0 2005 2010 2015 2020 2(125 2030 Year Gas l:>rrMuclion ! ()il Recovery 3O,000 25 ,(X)(} 20.00(} 15.0(}0 5,O00 2000 2(X)5 2010 2015 2020 > '~ 5 ~0 2030 Year 12 ~ 8 ¥ 6 2 2000 2(X}5 2010 2015 2020 2025 2030 Exhibit II-5: Production and Recovery Profiles ~3r Water Injection OH Production ,~-- sc f/stb ~,~ 8,0( ( t'~,% 1,200 ~ 60(X) 900 4,000 600 20(X) 300 2000 2005 20 I0 2015 2020 2025 2030 4,(X)(} AS{X) ~T LO(X) 2.5(}(/ 2.(~)0 1,5(X) 1 500 Water Production 2(×)0 2(×)5 2010 2015 2020 2025 Year 40 ()il Recovery 35 ~ 30 , 25 ;_ 20 V~ I5 0 10 2000 2005 20 I0 2015 2020 2025 2030 21X)O 2005 2010 20t5 2020 2025 2030 Exhibit III- 1 Aurora Well Tie-ins- Northern S-Pad To/From Mod~de 57 4 L~ne S 216 S 200 S-201 S-104 S 11)O S 213 S-l()3 S 1(}6 S-105 000 "0000000 To/From Module 93 Polaris Well Aurora Well IPA Well P¢~tential Well Piping Production/TestGas Lif~ Water Exhibit III-2' Aurora Facility Location Production (#) -- ' Test (#) Gas Lift (#) ~ Water (#) MI (#) Future Equipment (#) © Aurora Well ~ Existing Polaris Well iD ~ IPAWell # - Surface Satellite Equipment Injection Water Line Tie-in (IPA i~jection well) Exhibit IV-1' Typical Vertical Completion nipple 2000' X i~ipple (ID=3.81Y') XN nipple w/NoGo Conductor Casing ~ 20" casing Sm'face Casing 435YMD 3285'ssTVD <12d/4 hole 9-5/8 or 7-5/8' casing Tubing I/2 or 3]/2 ' Ct-80 Tbg 3 GLM's Production Pkr. 6600' ssTVD Ktlparuk C sand perl:~ Kupamk A sand peri), Pr(~luciion Casing 6900' sstvd < %7/8" hole 7 or 5-1/2 ' casing Exhibit IV-2: Typical Horizontal Completion X-aipple 0 2000' rtl t fRZ nipple (ID 3813") ->le w/N(X;O (ID=3 75') Fop Kup iruk 6673' sstvd lnlermediate Casing 10400' MD 6678' sstvd 9 7/8, hole 7 ol ~- I72" casiag Conductor Casing ~ 20" casing Su ri'ace Casing 4355' MD 3285'ssTVD !3 1/2 hole 10 3/4 or 9 5X¥ casiag Tubing 41/2 or 31/2 ' (r g0 Tbg 3GLM's 117~52' MD 6700 6712' sstvd 6 3/4 hole TREE = 4-1/8" 5M WELLHEAD= FMC 11" ACTUATOR= 'i~i3'i'"~'~''''~- 64.5 ~F~-' ............................................................ 3o0, ' ~x"~'h'~ie' ::- ....... 54"@ '2200 Datum MD = 8798 Datum TVD= 6700 SS 9-5/8" 40# L-80 BTCI [ 3736' Minimum ID = 3.725" @ XN nipple I Exhibit IV-3: Schrader-Kupa~' S-104i Injection Well SAFETY NOTES: ACTUAL DEPTHS WILL BE PROVIDED BEFORE COMPLETION STA MD 7VD DEV TYPE MAN LATCH GLM5 4839 3495 54 KBG-2-T/L BK GLM4 6731 4883 31 KBG-2-T/L BK GLM3 6920 5046 29 KBG-2-T/L BK SLSV 7035 5147 29 Baker CMU 13K GLM2 7117 5218 30 KBG-2-T/L BK SLS¥ 7175 5268 30 Baker CMU BK GLM1 7266 5347 30 KBG-2-T/L BK SLSV1 7333 5406 30 Baker CMU BK ,6842' [ I 4'1/2" X' 3'813" ID I __~sss3' I I Baker S-3, 7"x 4.5" I --,7061' I IBaker sABL'3 I --'7201' ] IBaker sABL'3 I I 4-1/2" 12.6#/ft L-80 I NSCT PERFORATION SUMMA RY REF LOG: Ref Platform Express GR/Res 1/27/2001 ANGLE AT TOP PERF: I 29 I Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 4.63 6 6920-6980 Open 2/4/2001 " 6 7018-7050 Open 2/4/2001 " 6 7070-7094 Open 2/4/2001 " 6 7114-7124 Open 2/4/2001 " 6 7162-7182 Open 2/4/2001 " 6 7216-7266 Open 2/4/2001 " 6 7280-7302 Open 2/4/2001 " 6 7325-7346 Open 2/4/2001 I~ I [ ~oo' I I 7" 26# L-80 m-BTC I [ g186' I I __--,8679' I IBake~sABL'3 I 8703' 1 [,,-~,~.,x,~.~.,.o I 8724' I I 4-1/2" XN, 3.725" ID I DATE REV BY COMMENTS 01/08/01 P. Smith Original Proposed Completion 02/09/01 P. Smith As-Completed PRUDHOE BAY UNIT/AURORA FIELD WELL: S-104i PERMIT No: 200-196 APl No: 50-029-22988-00 Sec. 35, T12N, R12E, 4494' FEL, 633' FNL BP Exploration (Alaska) Exhibit IV-4: Aurora and GC2 Water Properties 22 2,17 19601 .. -....?~ ~0754'~ 1640 ......... 247! 12600, 0.01 4.32;' ....... ~- 14~ 1561 ..~ 6.67" 6.9~ 821 107 9020: 80801 4' 26.2 381 560i ~32 ! 2:3 427 Exhibit V-1 AFFIDAVIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Gordon Pospisil, declare and affirm as follows: 1. I am the Supervisor of the Western Satellite Development for BP Exploration (Alaska) Inc., the designated operator of the Aurora Participating Area, and as such have responsibility for Aurora operations. 2. On 6'/g'/o ! , I caused copies of the Aurora Oil Pool, Pool Rules and Area Injection Application to be provided to the following surface owners and operators of all land within a quarter mile radius of the proposed injection areas: Operators: BP Exploration (Alaska) Inc. Attention: M. Cole P.O. Box 196612 Anchorage, AK 99519-6612 Surface Owners: State of Alaska Department of Natural Resources Attention: Dr. Mark Myers 550 West 7th Avenue, Suite 800 Anchorage, AK 99501-3510 Dated: Gordon Pospisil Declared and affirmed before me this/i~~ day of ",J'O~J~' ,,~,9~ ! . Notar1~Publi~n and for Alaska ! My commiss~o~ n expires: ~ Aurora Pool Rules and Area Injection Order Addendum I 7/23/01 Addendum 1 Section V. Production Allocation Paragraph 1 Aurora production allocation will be done according to the PBU Western Satellite Production Metering Plan. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC~2 allocation factor will be applied to adjust the total Aurora production. A minimum of two well tests one well test per month will be used to tune the performance curves, and to verify system performance. No NGLs will be allocated to Aurora. 1/1 #6 STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION AURORA POOL RULES AND AREA INJECTION ORDER JULY 24, 2001 9:00 AM NAME - AFFILIATION ADDRESS/PHONE NUMBER (PLEASE PRINT) #5 To: Subject: Gordon pospisil FW: Aurora Pool Rules and Area Injection Application Card for Tom Maunder The following responses have been prepared to questions/comments forwarded from Tom Maunder AOGCC staff on July 23rd. 1. Surface safety valves. Surface safety valves will be required on all wells. The inability to flow unassisted does not remove this requirement. Corrected on 7/24/01 submission. 2. Subsurface safety valves. There is insufficient information presented to support your request/proposal. Your staff should be prepared to present information regarding the risks and a hazard analysis with regard to omitting SSSVs from Aurora wells. Although the present Conservation Order for Prudhoe does not require SSSVs, we are aware that such valves are maintained in some wells. Your. application makes mention of MI injection wells as one type of well where such valves would/might be incorporated at Aurora. Response: The Aurora Pool Rules motion to the AOGCC concerning sub-surface safety valve requirements is based on modernizing Conservation Order (CO) 98A, which was generated in March of 1971. C0-98A required the installation of a Sub-Surface Safety Valve (SSSV) below the base of the permafrost. Aurora Pool Rules request that SSSV be installed only in Gas or Miscible Injectant (MI) injectors. Aurora producers are relatively low rate oil wells on artificial lift in a water flood development. SSSV's are not deemed useful for such wells. All wells (Producers, Water and MI injectors) will have Surface Safety Valves (SSV). installed. The SSSV requirement was originally requested by BPX based on the low level of experience with arctic production operations. With over three decades of arctic operations, BPX has gained substantial operating experience. The earlier request by BPX in the application which generated C0-98a was based on the potential freeze back of the permafrost; by placement of the SSSV it was thought that loss of well control, due to casing collapse would be prevented. Arctic design of casing strings and cement formation has clearly demonstrated that this is no longer a concern. A Consequence Assessment was completed in 1994 for Kuparuk River Unit; this assessment consisted of Hazard Identification, Hazard Analysis and Consequence Analysis. Subsequently, SSSV's were removed from the majority of wells from both the Prudhoe Bay Unit (PBU) and Kuparuk River Unit (KRU) without incident. The Consequence Assessment showed that there is no statistical difference in the predicted frequency of uncontrolled flow for Kuparuk Wells with or without SSSV's, 1.8 x 10-5/well year vs. 3.07 x 10-5 / well year, respectively. Given the extensive historical data used in the study, a factor of 5 (half an order of magnitude) would be required for a difference to be deemed statistically significant. Further, the assessment found that the frequency risk was a~tually higher in wells with SSSV's installed during Wireline and Workover Operations due to the increased work activity involving the SSSV. Again this risk was less than one half an order of magnitude difference so it is not considered an appreciable difference. 3. Mention is made of a "Prudhoe Bay Unit Western Satellite Metering Plan" Would you please provide a copy of this. Lc~osed as exhibit in 7 submission. Additional information should be ready to support a finding that and Borealis are indeed separate accumulations. Supplement 1 included in exhibits. 5. Figure IV-4 compares a S-105 water analysis with a GC2 water analysis. The S-105 is dated, but the GC2 is not. How has the GC2 analysis changed? Is the presented analysis what is expected through time? GC2 produced water is a mixture of seawater (original source of water injection) and Ivishak connate water. The current mixture is primarily seawater and is not expected to change dramatically over time. Relatively small volume of Kuparuk formation water is expected. 6. Injecting water above frac pressure should be addressed with regard to potential of fracing out of zone. Fracturing out of zone is addressed in the Area Injection Operations section; the upper bounding HRZ shale is greater than 100' thick. Log and core data indicate stress contrast between the HRZ and Kuparuk to contain injection above fracture pressure. 7. With production beginning, reservoir pressure has begun to decline. How does allowing the reservoir pressure to about 2600 psi prior to getting water injection underway effect recovery? Reservoir studies were completed to assess the impacts of primary production prior to waterflood startup in the Aurora Oil Pool. A history matched 3 phase, 3 dimensional reservoir simulator was used to evaluate changes in predicted ultimate recovery with pressure declines due to primary production. Based upon these results, no recovery losses are expected due to pressure declines to 2500 psi or above prior to waterflood startup. 8. With regard to MIT failures, your proposed action plan is'acceptable for water injectors, but if a MIT fail~re occurs on a MI well it should be SI and secured as soon as possible. Corrected in 7/24/01 submission. #4 STATE OF ALASKA i' NOTICE TO PUBLISHER ~'~ ADYERTI$1NC ORDER NO. ., ,~ ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO,, CERTIFIED ^FF,OAV,T OF PU~',OAT,ON (.~T2 Or ~ FO.M)W,~ A~AC.ED DOPY OF AO'0211427 ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F AOGCC AGENCY CONTACT DATE OF A.O. R 333 W 7th Ave, Ste 100 Jody Colombie June 21,2001 o Anchorage, AK 99501 PHONE PCN M - (907~ 793 -! 221 ~ATE~ ADVERTISEMENT REQUIRED: T Anchorage Daily News June 22, 200] o P O Box 149001 ENTIRETY ON THE BATES SltOWN. SPECIAL INSTRUCTIONS: Type of Advertisement [5~] Legal [-] Display [-"1 Classified [-1Other'{SPecify) SEE ATTACHED PUBLIC HEARING NOTICE , REF TYPE NUMBER AMOUNT DATE COMMENTS ~ VEN 2 ^~D 02910 3 , , 4 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIO 1 0] 02140]00 73540 2 3 . ,, 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving ^O.FRM Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 AD # DATE PO PRICE OTHER OTHER GRAND ACCOUNT PER DAY CHARGES CHARGES #2 TOTAL 930935 06/22/2001 STOF0330 $103.74 $0.00 $0.00 $103.74 $0.00 $0.00 $0.00 $103.74 $0.00 $0.00 $103.74 STATE OF ALASKA THIRD JUDICIAL Lorene Solivan, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English langua ge continuall., y as a daft¥ newsp.p.a er in Anchorage, Alaska, and it is now and during all sal~l time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and riot in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of safd period. That the full amount of the fee charged for the foregoing publi,caJ4on is not i_~.xce~s of the rate charged private indlvi~,' ~,~_~ (~ S i g n e d__~,_.__ ~,.~-=L(~;zJ~~~'~_ _ _ Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska . N.otice qf Pub!!:C Heorlng. J. ' STATE. OF;ALASKA ' A'loska' Oii,an~t Gas C0fi. server on~ Co'mmisslon ... , Pr~dhoe BoY~:~'El:e'ld :':P001.,} ,Rules opal Akefi Iniection' :'Order . · ' .'~.'1 nc.' bY letfe~, dat"~d J u~;: ~ 15,. 200,1, has; aPplle.d.fo~ '.,.a,h.. at.ea, in : Ond poo ! 'rU les'Under 20 / ,AAC 25.460,.0nd 20 AAC ?25 520, respectively:, .'e'r Le develo, pme~t STATE OF ALASKA '"" NOTICE TO PUBLISHER { ADVERTISING ORDI~'R NO. ADVERTISING IN(. . MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDEI~ I~O., CERTIFIED .. A~F,O^V,T OF PUBL,OAT,ON (.*.. 2 OF '.,S ~O..~)~,~, ~,~ ~O~ O~ AD'0211 42 7 ORDER ADVERTISEMENT MUST BE SUBMI~ED WITH I~OICE ~...' SEE '.B~OM 'E~:INV~. AODRESS.~v,; .;. . .'. '.~ ,...: .. :~.~)..~.......'.. ;.. ~:,.~:~?~$.,/~;.,,; ~,;r:~[?.. ...... F AO~C AGENCY CONTACT DATE OF A.~ ~ 333 West 7~ Avenue, Suite 100 ]odv Colombic o ~chorage, ~ 99501 PHONE PCN ~ - ~ (907~ 793 - 122 l ~ATE~ ~VERTISEMENT ~QUI~D: ~ ~chorage Daily News J~e 22, 2001 o P 0 Box 149001 THE ~TE~AL BE~EEN THE DOUBLE LINES MUST BE P~NTED IN ITS ~chorage, ~ 99514 ENTI~W ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF P 8LI¢ATION United states of America REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE division. THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION Before me, the undersigned, a nota~ public this day personally appeared M~T BE SUBMI~ED WITH THE INVOICE. A~ACH PROOF OF PUBLICATION HERE. who, being first duly swom, according to law, says that he/she is the of Published at in said division and state of and that the adve~isement, of which the annexed is a true copy, was published in said publication on the day of 2001, and thereafter for.., consecutive days, the last publication appearing on the __ day of ,2001, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This day of 2001, Nota~ public for state of My commission expires , ., 02-901 (Rev. 3/94) AO.FRM Page 2 PUBLISHER Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Aurora Oil Pool, Prudhoe Bay Field - Pool Rules and Area Injection Order BP Exploration (Alaska), Inc. by letter dated June 15, 2001, has applied for an area injection order and pool rules under 20 AAC 25.460 and 20 AAC 25.520, respectively, to enable development of the Aurora Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. A person may submit a written protest or written comments on the requested exemption prior to 4:00 PM on July 24, 2001 to the Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, Alaska 99501. In addition, the Commission has tentatively set a public hearing for July 24, 2001 at 9:00 am immediately following the public hearing on Niakuk Oil Pool at the Alaska Oil and Gas Conservation Commission, 333 W. 7th, Suite 100, Anchorage, Alaska. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission prior to 4:00 PM on July 16, 2001. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the tentative hearing, please call 793-1221. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before July 17, 2001. Cammy O~chsli Taylor {-) Chair Published June 22, 2001 ADN AO# 0211426 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Aurora Oil Pool, Prudhoe Bay Field - Pool Rules and Area Injection Order BP Exploration (Alaska), Inc. by letter dated June 15, 2001, has applied for an area injection order and pool rules under 20 AAC 25.460 and 20 AAC 25.520, respectively, to enable development of the Aurora Oil Pool, Prudhoe Bay Field, on the North Slope of Alaska. A person may submit a written protest or written comments on the requested exemption prior to 4:00 PM on July 24, 2001 to the Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, Alaska 99501. In addition, the Commission has tentatively set a public heating for July 24, 2001 at 9:00 am immediately following the public hearing on Niakuk Oil Pool at the Alaska Oil and Gas Conservation Commission, 333 Wi .7th, Suite 100, Anchorage, Alaska. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission prior to 4:00 PM on July 16, 2001. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the tentative hearing, please call 793-1221. If you are a person with a disability who may need a special mOdification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before July 17, 2001. ~3 ~'r~ cammy~O chsli Taylo Chair Published June 22, 2001 ADN AO# 0211426 of the above ~ faxed/mailed to each of the folloW, ring a.t their ~_~a~ldmsses of, / PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION P O BOX 2221 NEW YORK, NY 10163-2221 OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX8485 GATHERSBURG, MD 20898 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 AMOCO CORP 2002A, LIBRARY/INFO CTR P O BOX 87703 CHICAGO, IL 60680-0703 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 MURPHY E&P CO, ROBERT F SAWYER P O BOX 61780 NEW ORLEANS, LA 70161 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 IOGCC, P O BOX 53127 OKLAHOMA CITY, OK 73152-3127 R E MCMILLEN CONSULT GEOL 2O2 E 16TH ST OWASSO, OK 74055-4905 OIL & GAS JOURNAL, LAURA BELL P O BOX 1260 TULSA, OK 74101 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 BAPI RAJU 335 PINYON LN COPPELL, TX 75019 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 DEGOLYER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 STANDARD AMERICAN OIL CO, AL GRIFFITH P O BOX 370 GRANBURY, TX 76048 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 SHELL WESTERN E&P INC, G.S. NADY P O BOX 576 HOUSTON, TX 77001-0574 ENERGY GRAPHICS, MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 H J GRUY, ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 , RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 P O BOX 4813 HOUSTON, TX 77210 UNOCAL, REVENUE ACCOUNTING P O BOX 4531 HOUSTON, TX 77210-4531 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 P O BOX 4778 HOUSTON, TX 77210-4778 EXXON EXPLORATION CO., T E ALFORD P O BOX 4778 HOUSTON, TX 77210-4778 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLINGTON P O BOX 1635 HOUSTON, TX 77251 PETR INFO, DAVID PHILLIPS P O BOX 1702 HOUSTON, TX 77251-1702 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 WORLD OIL, DONNA WILLIAMS P O BOX 2608 HOUSTON, TX 77252 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 P O BOX 2180 HOUSTON, TX 77252-2180 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 P O BOX 2180 HOUSTON, TX 77252-2180 PENNZOIL E&P, WILL D MCCROCKLIN P O BOX 2967 HOUSTON, TX 77252-2967 CHEVRON CHEM CO, LIBRARY & INFO CTR P O BOX 2100 HOUSTON, TX 77252-9987 MARATHON, Ms. Norma L. Calvert P O BOX 3128, Ste 3915 HOUSTON, TX 77253-3128 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TEXACO INC, R Ewing Clemons P O BOX 430 BELLAIRE, TX 77402-0430 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 INTL OIL SCOUTS, MASON MAP SERV INC P O BOX 338 AUSTIN, TX 78767 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 GEORGE G VAUGHT JR P O BOX 13557 DENVER, CO 80201 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 C & R INDUSTRIES, INC.,, KURT SALTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING P O BOX 1655 COLORADO SPRINGS, CO 1655 80901- RUBICON PETROLEUM, LLC, BRUCE I CLARDY SlX PINE ROAD COLORADO SPRINGS, CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 MUNGER OIL INFOR SERV INC, P O BOX 45738 LOS ANGELES, CA 90045-0738 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 BABSON & SHEPPARD, JOHN f BERGQUIST P O BOX 8279 VIKING STN LONG BEACH, CA 90808-0279 ANTONIO MADRID P O BOX 94625 PASADENA, CA 91109 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 TEXACO INC, Portfolio Team Manager R W HILL P O BOX 5197x Bakersfield, CA 93388 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 ECONOMIC INSIGHT INC, SAM VAN VACTOR P O BOX 683 PORTLAND, OR 97207 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 715 1 ST #4 ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 FORCENERGY INC., JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE, AK 99501 YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 GAFO, GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WILLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF REVENUE, OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DNR, DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 ARLEN EHM GEOL CONSLTNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 US BLM AK DIST Of C, RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507-2899 UON ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 ! GORDON J. SEVERSON 3201 WESTMAR ClR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, LIBRARY 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE, AK 99508.4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE, AK 99508-4363 ! JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ClRI, LAND DEPT P O BOX 93330 ANCHORAGE, Ak 99509-3330 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 ANCHORAGE TIMES, BERT TARRANT P O BOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER P O BOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 P O BOX 10036O ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, JOANN GRUBER ATO 712 P O BOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 P O BOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON P O BOX 102278 ANCHORAGE, AK 99510-2278 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 P O BOX 196105 ANCHORAGE, AK 99510-6105 ALYESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ALYESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY P O BOX 149001 ANCHORAGE, AK 99514 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE, AK 99518 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 OPSTAD & ASSOC, ERIK A OPSTAD PROF GEOL P O BOX 190754 ANCHORAGE, AK 99519 JACK O HAKKILA P O BOX 190083 ANCHORAGE, AK 99519-0083 ENSTAR NATURAL GAS CO, BARRETT HATCHES P O BOX 190288 ANCHORAGE, AK 99519-0288 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON P O BOX 196168 ANCHORAGE, AK 99519-6168 MARATHON OIL CO, LAND BROCK RIDDLE P O BOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, P O BOX 196247 ANCHORAGE, AK 99519-6247 UNOCAL, KEVIN TABLER P O BOX 196247 ANCHORAGE, AK 99519-6247 EXXONMOBIL PRODUCTION COMPANY, MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA), INC., MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, SUE MILLER P O BOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, PETE ZSELECZKY LAND MGR P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 P O BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA)INC, MR. DAVIS, ESQ P O BOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 AMSI/VALLEE CO INC, WILLIAM O VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 D a PLATT & assoc, 9852 LITTLE DIOMEDE ClR EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER P O BOX 772805 EAGLE RIVER, AK 99577-2805 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 RON DOLCHOK BOX 83 KENAI, AK 99611 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P O DRAWER 66 KENAI, AK 99611 DOCUMENT SERVICE CO, JOHN PARKER P O BOX 1468 KENAI, AK 99611-1468 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN P O BOX 3029 KENAI, AK 99611-3029 NANCY LORD PO BOX 558 HOMER, AK 99623 PENNY VADLA P O BOX 467 NINILCHIK, AK 99639 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 JAMES GIBBS P O BOX 1597 SOLDOTNA, AK 99669 PACE, SHEILA DICKSON P O BOX 2018 SOLDOTNA, AK 99669 KENAI NATL WILDLIFE REFUGE, REFUGE MGR P O BOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ PIONEER, P O BOX 367 VALDEZ, AK 99686 ALYESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK P O BOX 300 MS/701 VALDEZ, AK 99686 VALDEZ VANGUARD, EDITOR P O BOX 98 VALDEZ, AK 99686-0098 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 RICK WAGNER P O BOX 60868 FAIRBANKS, AK 99706 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY P O BOX 70710 FAIRBANKS, AK 99707 C BURGLIN P O BOX 131 FAIRBANKS, AK 99707 FRED PRATT P O BOX 72981 FAIRBANKS, AK 99707-2981 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 K&K RECYCL INC, P O BOX 58055 FAIRBANKS, AK 99711 ASRC, BILL THOMAS P O BOX 129 BARROW, AK 99723 RICHARD FINEBERG P O BOX 416 ESTER, AK 99725 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL P O BOX 755880 FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 #3 BP Exploration (Alaska)!, 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 bp June 15, 2001 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 FIE: Aurora Pool Rules And Area Injection Application Dear Commissioners: Enclosed is the resubmission of Pool Rules and Area Injection Application for the Aurora Oil Pool. We look forward to discussing this report with you further and setting a hearing date after the 30-day public notice period has ended. BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that a hearing commence as early as possible in order to gain approval of an Area Injection Order. Facilities to begin water flood operations are expected to be available in July 2001. Please contact the authors if you have any questions or comments regarding this request. Sincerely, Gordon Pospisil GPB Satellites Manager Attachments Author Name Jim Young Ed Westergaard Bruce Weiler Gary Molinero Fred Bakun CC' Randy Frazier (BP) J. P. Johnson (PAl) Position Office Ops. Eng. 564-5754 Dev. Geologist 564-5972 Facility Eng. 564-4350 Geophysicist 564-5103 Res. Eng 564-5173 M. P. Evans (ExxonMobil) P. White (Forest Oil) Aurora Pool Rules and Area .on Order 6/15/2001 Aurora Pool Rules And Area Injection Application June 15, 2001 1/40 Aurora Pool Rules and Area l~a .on Order 6/15/2001 I. Geology ........................................................................................................................... 3 Introduction ..................................................................................................................... 3 Stratigraphy ..................................................................................................................... 3 Structure .......................................................................................................................... 7 Fluid Contacts ................................................................................................................. 9 Pool Limits ...................................................................................................................... 9 II. Reservoir Description and Development Planning ..................................................... 10 Rock and Fluid Properties ............................................................................................. 10 Hydrocarbons in Place .................................................................................................. 12 Reservoir Performance .................................................................................................. 12 Development Planning ................................................................................................. 15 Model Results ................................................................................................................ 15 Development Plans ........................................................................................................ 16 Reservoir Management Strategy ................................................................................... 17 III. Facilities ..................................................................................................................... 19 General Overview ......................................................................................................... 19 Drill Sites, Pads, and Roads .......................................................................................... 19 Pad Facilities and Operations ........................................................................................ 20 Production Center .......................................................................................................... 21 IV. Well Operations ......................................................................................................... 22 Drilling and Well Design .............................................................................................. 22 Reservoir Surveillance Program .................................................................................... 26 V. Production Allocation .................................................................................................. 28 VI. Area Injection Operations .......................................................................................... 29 Plat of Project Area ....................................................................................................... 29 Operators/Surface Owners ............................................................................................ 29 Description of Operation ............................................................................................... 29 Geologic Information .................................................................................................... 30 Injection Well Casing Information ................................................................................ 30 Injection Fluids .............................................................................................................. 30 Injection Pressures ......................................................................................................... 32 Fracture Information ..................................................................................................... 32 Hydrocarbon Recovery ................................................................................................. 34 VII. Proposed Aurora Oil Pool Rules ............................................................................... 35 VIII. Area Injection Application ....................................................................................... 38 IX. List of Exhibits ........................................................................................................... 40 2/40 Aurora Pool Rules and Area ~.,on Order 6115/2001 I. Geology Introduction The Aurora Pool is located on Alaska's North Slope, as illustrated in Exhibit I-1. The Aurora Pool was confirmed in 1999 by the drilling of the V-200 well. The reservoir interval for the Aurora Pool is the Kuparuk River Formation. The Aurora Pool overlies the Prudhoe Bay Unit (PBU) Sadlerochit Group reservoirs in the vicinity of S-Pad. In addition to the V-200 well, the S- 100, S- 101, S- 102, S- 103, S- 104, and S- 105 wells are recent Kupamk River Formation penetrations in this area. The North Kupamk 26-12-12 and Beechey Point State #1 wells, both drilled in 1969, were the first wells to penetrate and test hydrocarbons in the Aurora Pool. A number of PBU Sag River/Ivishak development wells also penetrated the overlying Kupamk River Formation. The S-24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. Four S-Pad and M-Pad well penetrations and Term Well C define the southeastern limit of the Aurora accumulation. As shown in Exhibit 1-2, the top of the Aurora structure crests at 6450 feet true vertical depth sub-sea (tvdss). The deepest interpreted oil-water contact (OWC) is at 6835 feet (tvdss) in the Beechey Point State # 2 well. Exhibit 1-3 shows the location of the Aurora Participating Area (APA), including expansion areas identified by the Department of Natural Resources. The area encompassed by the Aurora Pool would be removed from the Prudhoe Bay Field Kuparuk River Oil Pool rules area under Conservation Order 98-A. Stratigraphy The productive interval of the Aurora Pool is the Kupamk River Formation, informally referred to as the "Kuparuk Formation". This formation was deposited during the Early Cretaceous geologic time period, between 120 and 145 million years before present. Exhibit 1-4 shows a portion of the open-hole wireline logs from the V-200 well. This "type log" illustrates the stratigraphic definition of the Aurora Pool. The log is scaled in true vertical depth subsea and also has a measured depth (md) track. In the V-200 well, the top of Kuparuk Formation occurs at 6,693 ft. tvdss (6,858.5 ft. md) and the base occurs at 7,070 ft. tvdss (7,253.5 ft. md). 3/40 Aurora Pool Rules and Area .,on Order 6/15/2001 The Kuparuk Formation was deposited as marine shoreface and offshore sediments, and is composed of very fine to medium grained quartz-rich sandstone, which is interbedded with siltstone and mudstone. The sandstones typically have higher resistivity (3-50 ohm- meters) than the surrounding lithologic units. The Kuparuk Formation base is bounded by its contact with the Early Cretaceous-age Miluveach Formation and is distinguished by a change in lithology and conventional electric log character. The Miluveach Formation is shale with low resistivity (1 to 3 ohm-meters). The Kupamk Formation top is defined by its contact with the Early Cretaceous-age Kalubik Formation or the overlying Early Cretaceous-age High Radioactive Zone (HRZ) Formation. Both are shales, and they are distinguished from the Kupamk River Formation by a change in lithology and conventional electric log character. The Kalubik Formation is a dark gray shale with a Gamma Ray log signature of 80 to 135 API units, and the HRZ is a black, organic-rich shale with a Gamma Ray log signature typically greater than 150 gamma API units. The Kupamk Formation in the Aurora Pool is stratigraphically complex, characterized by multiple unconformities, changes in thickness and sedimentary facies, and local diagenetic cementation. As shown on the type log in Exhibit 1-4, the Kupamk Formation is divided into three stratigraphic intervals, from oldest to youngest, the A, B, and C intervals, with the A and C intervals divided into a number of sub-intervals. An overlying unit, called the D Shale, is locally present in the northern part of the Aurora Pool. Three unconformities affect Kupamk thickness and stratigraphy. The Lower Cretaceous Unconformity (LCU) has erosional topography. It truncates downward and dips to the east where it successively removes the Kuparuk B and Kupamk A intervals. The C-4 Unconformity also truncates downward to the east progressively removing the C-4A, C- 3B, C-3A, C-2, and C-1 sub-intervals before merging with the LCU. A younger unconformity, called the Pre-Aptian Unconformity also affects the Aurora Pool. At the Beechey Point wells in the western portion of the Aurora Pool, the Kuparuk Formation is 4/40 Aurora Pool Rules and Area In{i. .on Order 6/i 5/2001 unaffected and the HRZ interval above this unconformity is in contact with the Kalubik Formation. However, this unconformity also truncates downward to the east. At the V- 200 well and other S-Pad wells to the east, the Kalubik Formation is eroded, and the HRZ interval is in contact with the Kuparuk C-4B sub-interval. This Pre-Aptian Unconformity eventually truncates the Kuparuk C-4B and the C-4A locally, and merges with the C-4 Unconformity and the Lower Cretaceous Unconformity at the eastern edge of the Aurora area. The Kuparuk A and B units have a distinctly different stratigraphic thickness trend than the Kupamk C units. Where not truncated, the lower A unit maintains a nearly uniform thickness throughout the Aurora area, suggesting that its deposition pre-dates significant fault movement. In contrast, the thickness, lithofacies, and diagenesis of the C units are variable and have been influenced by differential erosion, and variable diagenetic fluid effects. As a result of these processes, the entire Kuparuk C interval thins south and southeastward and reservoir quality varies laterally and vertically. The lower Kuparuk A interval contains two reservoir quality sub-intervals; the A-4 and A-5 sand units, which are 30 feet and 20 feet thick, respectively. In the V-200 well, these sands are wet. In structurally higher portions of the field to the east, these A sand units are expected to be oil-bearing and productive. The A-5 sand appears to be higher quality reservoir than the A-4 sand. The overlying Kuparuk B interval is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are up to 3 feet thick. In the V-200 well, wireline logs show these thin B interval sands to be wet. The uppermost unit, the Kupamk C interval, contains the primary reservoir sands of the Aurora Pool. The thickness of this interval 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 lithology of this upper unit is variable, consisting of interbedded very fine-grained to medium-grained sandstone with minor amounts of muddy siltstone and sandy-silty mudstone. The Kuparuk C sands are generally very quartzose and 5/40 Aurora Pool Rules and Area I ,n Order 6/15/2001 moderately sorted. The Kuparuk C interval is intensely bioturbated, contributing to the heterogeneous nature of the Kuparuk C. The Kupamk C is further subdivided into the following sub-intervals from oldest to youngest: C-l, C-2, C-3A, C-3B, C-4A, and C- 4B. The C-1 overlies the Lower Cretaceous Unconformity. The Kuparuk C-1 and C-4B sub-intervals are coarser grained and contain variable amounts of glauconite and diagenetic siderite. The volume and distribution of siderite and glauconite plays an important role in the reservoir quality of the Kupamk C-1 and C-4B intervals. These minerals are unevenly distributed and may affect a portion of the rock volume in the C-1 and C-4B sub-intervals. Due to the increase in structural clay volume, compaction, and cementation, the porosity, permeability, and productivity of these sub-intervals are reduced. The C-1 is the coarsest grained sub-interval. It is a well-sorted medium-grained sandstone with occasional coarse and very-coarse grains. The C-1 has a fairly uniform thickness of 14 feet to 18 feet except to the southeast where it thins due to truncation. The upper portion of the C-1 sub-interval gradationally fines upward into the C-2 sub- interval. The C-2 sub-interval is the finest grained unit of the Kupamk C interval and is considered non-reservoir. In the western portion of the Aurora Pool, it is dominated by silty mudstone with occasional very fine-grained sand laminations and interbeds. In the eastern part of th Aurora, the C-2 lithology transitions to very fine-grained muddy-silty sandstone, indicating a lateral facies change from west to east. The C-2 interval has a somewhat uniform thickness of 28 feet to 36 feet in the western part of the field. The C-2 thins to the southeast and is eventually truncated. The C-3A sub-interval is composed of coarsening upward sandstone beds interbedded with silty mudstone. The sandstone beds range from 1 to 2 feet thick, silty, very fine- grain sand at the base up to 10 feet thick, fine-grained sand at the top. The mudstone interbeds display lateral facies variation, similar to the underlying C-2 sub-interval, in that they coarsen eastward to silty very fine-grained sandstone toward the truncation. The overlying C-3B sub-interval is distinguishable from the underlying C-3A sub- 6/40 Aurora Pool Rules and Area on Order 6/i 5/2001 interval. The sandstones amalgamate and the mudstone interbeds are not present. The C-4A sub-interval continues the coarsening upward trend from fine-grained sandstone at the base to medium-grained sandstone toward the top. Due to the relatively coarse grain size and low volume of clay matrix, the C-4A sub-interval has the highest net to gross and reservoir quality in the Kuparuk Formation in the Aurora Pool area. The C-4A and C-4B sub-intervals are separated by an intra-formational unconformity that marks the end of the coarsening upward trend. This unconformity, called the C-4 Unconformity, is a disconformity in the western half of the accumulation. However, it truncates downward through the stratigraphic section in the eastern half of Aurora, where it eventually merges with the Lower Cretaceous Unconformity. The top portion of the C- 4B is a fining upward sequence into the overlying Kalubik Formation. C-4 interval thickness varies due to interaction by unconformities. The interval is thickest at the Beechey Point area where total C-4 thickness exceeds 60 feet. The interval thins southeastward and is eventually truncated. Structure Exhibit 1-2 is a structure map on the top of the Kupamk Formation with a contour interval of 25 feet. Top Kupamk structure in the Aurora area is essentially a northwest-southeast oriented ridge, which is broken up by north-south striking faults. Gentle slopes dipping 2.5 to 6.5 degrees away from the structural crest characterize the northeast and southwest flanks of the ridge. In contrast, rotated fault blocks characterize the southern and western flanks of the ridge. 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 well. The southeastern terminus of the Aurora Pool is coincident with the "Prudhoe High", a large basement-involved structural uplift that underlies the Prudhoe Bay field. Early Cretaceous and older sediments lapped' over this structural high, and were later uplifted and subsequently beveled off by unconformities. Thus, this major structural high east of the Aurora accumulation is devoid of Kuparuk. The Kupamk Formation thins 7/40 Aurora Pool Rules and Area on Order 6/15/2001 southeastward to a zero edge against the Prudhoe High. The erosional truncation is orthogonal to the northwestern orientation of the overall structural ridge As shown on Exhibit 1-5, Aurora can be divided into five structurally defined areas. (1) The Beechey Block, the westernmost area is a complexly faulted area upthrown to a major north-south fault. The Beechey Point wells were drilled in this area. (2) The V- 200 Block is a structurally stable area between the Beechey Block to the west and the north-south bisecting fault to the east.. The V-200 well and the first group of horizontal development wells (S-100, S-101, S-102) penetrate this block. (3) The Crest Block is an intensely faulted area on the upthrown (eastern) side of the north-south bisecting fault. The top of the Kuparuk horizon reaches its structural crest at 6,450 ft. tvdss in the Crest Block. Ten S-Pad Sag River/Ivishak wells have penetrated the Kuparuk Formation in this block. (4) The North of Crest Block lies north of the Crest Block and east of the major north-south fault. The North Kuparuk 26-12-12 and Aurora development wells S- 103, S-104, and S-105 provide well control in this block. (5) The Eastern Block includes the area east of another north-south fault system near the S-08 and S-02 wells. This block is less structurally complex than the Crest Block and includes the southeastern thinning and truncation of the Kuparuk reservoir. Eight S-Pad Sag River/Ivishak wells penetrate the Kuparuk Formation in this block. Exhibit 1-6 is a northwest-southeast oriented structural cross-section along the axis of the Aurora structural ridge (see Exhibit 1-2 for location). This cross-section illustrates the effect of north-south oriented faulting as well as the eastern truncation of the Kuparuk reservoir by the three unconformities. Exhibit 1-7 is a dip-oriented seismic traverse at the same northwest-southeast location as the cross section (see Exhibit 1-2 for location). This exhibit shows the overlying and underlying stratigraphy, as well as the fault complexity of the area. Exhibit 1-8 is a strike-oriented seismic traverse from southwest to northeast (see Exhibit 1-2 for location). It shows a cross view of the structural ridge that forms the Aurora Pool, and it also illustrates how fault complexity varies at different stratigraphic horizons. 8/40 Aurora Pool Rules and Area( .ion Order 6/15/2001 Fluid Contacts Exhibit I-9 shows the interpreted Oil/Water Contacts (OWCs) and Gas/Oil Contacts (GOCs) in the Aurora Pool. Based on wireline logs, OWCs have been interpreted in the North Kuparuk 26-12-12 well at 6812 feet tvdss and at 6835 feet tvdss in the Beechey Point State #2 well. Repeat Formation Tester (RFT) pressure gradient data in the V-200 well indicate a free water level at 6824 feet tvdss. These data suggest either a 23 feet range of OWC uncertainty or compartmentalization of the Aurora fault blocks and a westward deepening of the OWC across the Aurora area. At present a common GOC for the Aurora' Pool has not been identified. Based on wireline logs, core analysis saturations, and core staining, a GOC is interpreted in the S- 16 well at 6631 feet tvdss. Based on well tests, mudlog and wireline logs, a. GOC is interpreted in the Beechey Point State #1 well at 6678 feet tvdss. Sidewall core saturations and staining, and RFT pressure gradient data and fluid samples from the S-31 and S-24A wells in the Crest Block indicate oil above the GOC depths in the S-16 and Beechey Point State #1 wells. The Crest Block appears to be gas free. Pool Limits The trap for oil and gas in the Aurora Pool is created by a combination of structural and stratigraphic features. The accumulation is bounded to the west by several faults where the reservoir is juxtaposed against impermeable shales of the overlying Kalubik Formation and HRZ Shale. To the southwest and north, the pool limit is defined by the down-dip intersection of the top of reservoir with the oil-water contact. To the east and southeast the reservoir is truncated by the Pre-Aptian, C-4, and Lower Cretaceous Unconformities. These unconformities merge at the southeastern limit of the field. The boundary of the Aurora PA, including the Expansion Areas, is within the proposed boundary of the Aurora Pool. Exhibits I-10 through I-!2 are net sandstone maps of the Aurora Pool with a contour interval of 10 feet. Exhibit 1-13 is a net hydrocarbon pore foot map of the Aurora Pool with a contour interval of 10 feet. 9/40 Aurora Pool Rules and Area ~ ,ion Order 6/1512001 II. Reservoir Description and Development Planning Rock and Fluid Properties The reservoir description for the Aurora Pool is developed from the Aurora Log Model. Geolog's Multimin is used as the porosity/lithology 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 lithologic 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 #1, S-04 and S-16. Porosity and Permeability Porosity and permeability measurements were based upon routine core analysis (air permeability with Klinkenberg correction) from the following well set: S-16, S-04, Beechey Point State #1, NWE 1-01, NWE 1-02, and NWE 2-01. The ratio of vertical to horizontal permeability (kv/kh) was 0.006 per 20 feet interval, based on the harmonic average of routine core data. Typical single plug kv/kh ratios ranged from 0.4 to 1.2. Exhibit II-1 shows values for porosity and permeability by zone that were used in the reservoir simulation. Net Pay Net pay was determined from the following criteria: minimum porosity of 15%, Vclay < 28%, and Vglauconite <40%. If the volume of siderite exceeded 30%, the net pay was discounted by a factor of 0.5. Exhibit II-1 shows gross thickness by zone based on marker picks and net pay based on the Aurora Log Model criteria. The 15% porosity cut off corresponds to approximately 1 md of permeability and what could reasonably be expected to be reservoir. Exhibit 11-6 shows a cross plot of porosity vs permeability. 10/40 6/15/2001 Water Saturation Water saturations for the Aurora reservoir model were derived using mercury injection capillary pressure (MICP) analyses from S-04 and S-16 core. The distribution of the data was characterized using two distinct Leverett J-functions for rock with >20md and <20md permeability. The capillary pressure data were then used to initialize the Aurora reservoir model utilizing initial water saturations as shown in Exhibit II-1. Relative Permeability Relative permeability curves for Aurora were derived by comparison to analogs on the North Slope. The crude oil from Aurora was evaluated against other North Slope reservoirs. In terms of AP1 gravity and chemical composition, the Aurora crude most closely resembles Prudhoe Bay and Pt. Mclntyre crude. The Kuparuk sands within the Aurora Pool resemble two Pt. Mclntyre rock sub-types, referred to as rock type #6 (for permeability >20md) and rock type #8 (permeability <20md). The relative permeability curves generated for these Pt. Mclntyre rock types were employed in the Aurora reservoir model. Wettability Based on the relatively light nature of the Aurora crude and relative permeability data from the Pt. Mclntyre analog, the reservoir is expected to be intermediate to water wet. Initial Pressure & Temperature Based on RFT data from V-200, the initial reservoir pressure is estimated at 3433 psia at the reservoir datum of 6700 feet tvdss. The reservoir temperature is approximately 150 degrees Fahrenheit at this datum. Fluid PVT Data Reservoir fluid PVT studies were conducted on V-200 crude from recombined surface test separator samples and RFT downhole samples. The reservoir pressure was 3433 psia at 6700 feet tvdss (datum). The API gravity was 29.1° with a solution gas oil ratio (GOR) of 717 scf/stb. The formation volume factor was 1.345 RVB/STB and the oil 11/40 Aurora Pool Rules and Area .~ .don Order 6/15/2001 viscosity was 0.722 centipoise at reservoir pressure and temperature. The bubble point for Aurora crude varied according to the sampling method. RFT samples from V-200 had bubble points ranging from 3028 psig to 3590 psig. This dispersion is most likely due to the sampling process. The recombined surface samples had a bubble point of 3073 psig. Exhibit I1-2 shows a summary of the fluid properties for the Aurora accumulation. Exhibit 1I-3 contains a listing of PVT properties as a function of pressure. 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. Formation gas in place ranges from 75 to 100 bscf, and gas cap gas ranges from 15 to 75 bscf. Reservoir Performance Well Performance Eight wells have been tested in the Kupamk formation at Aurora. Five of the test wells (Beechey Point State 4/1, Beechey Point State 4/2, North Kuparuk 26-12-12, V-200, and S-24Ai) are unavailable for Aurora production. Six development wells have been completed and tested in the Kupamk (S-100, S-101, S-102, S-103, S-104 and S-105). The Beechey Point State 4/1 well was tested twice, producing 1334 mmscfd gas (17.8 bopd condensate) and 2700 mmscfd gas. A GOC pick was not clearly defined, but based on interpreted wireline log and test data the GOC is possibly at 6678 feet tvdss, but could range from 6648 feet tvdss to 6705 feet tvdss. Pressure buildup analysis indicates that the Kupamk sands were badly damaged with a skin in excess of +50. In Beechey Point State//2, an attempt to test the Kuparuk horizon was made, but the formation would not flow. It is suspected that the Kupamk sands were badly damaged during drilling based on the high skin from Beechey Point State #1. An OWC is interpreted at 6835 feet tvdss from sidewall core data and logs. 12/40 Aurora Pool Rules and Area . .non Order 6/15/200 i The North Kupamk 26-12-12 well had three flow tests performed in the Kupamk. The first produced 8 bbls of oil over 2-6 hours, the second produced 32 bopd, and the third 28 bopd. An OWC was interpreted at 6812 feet tvdss from logs. Oil API gravity ranged from 25.2 to 26.4 degrees. The V-200 encountered oil in the Kupamk and a free water level was calculated from RFT pressure data at 6824 feet tvdss. The V-200 was tested in four stages while progressively adding perforations uphole. The initial test, with perforations at 6900 - 6920 feet MD, tested at 387 bopd with a GOR of 541 scf/stb. The second production test opened an additional 20 feet of formation (6880-6920 feet MD) and tested at 1517 bopd with a GOR of 535 scf/stb from both intervals. After the second set of perforations was added, surface PVT samples were collected and a pressure transient test was performed. The third production test opened a further 18 feet of formation (6862-6920 feet MD) and tested at 1801 bopd with a GOR of 677 scf/stb from all three intervals. When the well was logged, a final production test flowed at a rate of 1915 bopd with a GOR of 718 scf/stb from all three intervals. The S-24Ai well was not flow tested, but RFT data were collected. The entire Kuparuk interval was oil bearing and no gas or water contact was detected. The RFT pressures and oil gradient were sufficiently different (11 psi at common tvdss) from V-200 to suggest that the S-24Ai fault block is isolated from the V-200 fault block. The API gravity of the RFT sample was 25.6 degrees. S-100 was drilled as a horizontal well in the V-200 fault block in Phase I of Aurora development drilling. Log analysis indicates S-100 has over 1500 feet of net pay. The well was brought on line in November 2000 and the initial well test produced 7,230 bopd at a GOR of 831 scf/stb. Initial AP1 gravity was 26°. S-101 was drilled as a horizontal well in the southern portion of the V-200 fault block as the second well of Phase I development drilling. Log analysis indicates the well has over 2500 feet of net pay. A December 2000 production test produced 1062 bopd at a GOR of 20707 scf/stb. Well logs suggest a possible GOC in the toe of the well at ~6680 feet 13/40 Aurora Pool Rules and Area(,.~ .~tion Order 6/15/2001 tvdss. Initial API gravity was 47°. The elevated API was due to the production of gas condensate liquids. S-102 was drilled as a horizontal well in the northem portion of the V-200 fault block as the third well of Phase I development drilling. Log analysis indicates that the well has approximately 400 feet of net pay and that the reservoir is of considerably lower quality than for the S-100 and S-101 wells. A December 2000 test produced 458 bopd at a GOR of 12005 scf/stb. Initial API gravity was 26°. Aquifer Influx The aquifer to the north of Aurora could provide pressure support during field development. Early production data from the flanks of the field will be evaluated to determine the extent of pressure support. Current modeling efforts, both with and without a Fetkovich aquifer, do not significantly change injector requirements or location. As production data become available this assessment could change. Gas Coning / Under-Running Log and RFT data were integrated with the Aurora structure map to identify free gas in the. Aurora Pool. It is likely that there are three to five small discrete gas caps located throughout the accumulation. Beechey Point State #1 logs suggest a GOC at 6678 feet tvdSs in the western portion of the Aurora Pool. Sidewall core from S-31 and RFT fluid samples from S-24Ai in the central portion of the accumulation suggest that this fault block is filled with oil to the crest of the structure. Log and core data from S-16 indicate the Eastern Block may have a GOC at 6631 feet tvdss. Initial production from development wells may produce gas cap gas through coning or under-mn mechanisms. This gas volume could impact early well performance, but the effect should dissipate as the small gas caps are produced and pressure maintenance is initiated. The current depletion plan is to produce any associated gas, while evaluating well work options. As production and reservoir surveillance data become available, this interpretation could alter substantially. 14/40 Aurora Pool Rules and Area In) ....... on Order 6115/2001 Development Planning A reservoir model of the Aurora Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. Reservoir Model Construction A fine scale three-dimensional geologic model of Aurora was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk reservoir volume and distribution of porosity for the Aurora reservoir model. This reservoir model is a three-dimensional, three-phase, black oil simulator. The model area encompasses the known extent of the Aurora accumulation. The model has 300 feet by 300 feet (2.0 acre) cells. The reservoir model is defined vertically with five layers that have a nominal thickness of five to 20 feet. Exhibit II-1 shows the correspondence of model layers to geologic zones and summarizes average physical properties for each model layer. Faults and juxtaposition are honored in the model through the use of comer point geometry and non-local grid connections. Water saturations in the reservoir model were established by capillary pressure equilibrium. Two Leverett J-Curves were used for >20md and <20md rock. Oil water contacts were varied across the field from 6812 feet to 6835 feet tvdss based on available data (log, RFT, etc.) from each fault block. The reservoir pressure was set to 3433 psia at the datum of 6700 feet tvdss. Model Results Two development options were evaluated for Aurora: primary depletion and waterflood. Primary Recovery The primary recovery mechanism was a combination of solution gas drive, gas cap expansion, and aquifer support. Model results indicate that primary depletion would recover approximately 12% of the OOIP. Exhibit 11-4 shows production and recovery profiles for primary depletion. Under primary depletion, the Aurora Pool experiences a rapid decline in reservoir pressure that falls below 2000 psig by year 2006. Production 15/40 Aurora Pool Rules and AreJ .... tion Order 6/15/2001 rate peaks at 7000 to 9000 bopd. Waterflood Waterflood has been identified as the preferred development option for Aurora. It is anticipated that field development will require ten to thirteen producers and five to seven injectors. The reservoir simulation of waterflood reached a recovery of 34% of the OOIP with 0.50 hydrocarbon pore volume injected (HCPVI). Exhibit 11-5 shows production and recovery profiles for an Aurora Waterflood development. Production rate peaks at 14,000 - 17,000 bopd with a maximum water injection rate of 20,000- 30,000 bwpd. Enhanced Oil Recovery (EOR) Preliminary analysis indicates the potential for miscible gas flood in the Aurora accumulation. Early screening indicates on the order of 5% incremental oil recovery. Further evaluations need to be performed to determine the impact on total recovery. Development Plans Phase I Development Phase 1 development focuses on the V-200 Block and North of Crest Block. Several waterflood development options were studied using the Aurora reservoir simulator. Initial studies focused on the V-200 fault block to optimize well location and producer/injector placement. The base development consists of three horizontal wells to develop and further evaluate the V-200 Block (S-100, S-101, S-102). Development drilling data indicates the presence of a gas cap at a log-interpreted depth of ~6680 feet tvdss. Simulation studies indicate recovery from the V-200 block can be optimized by converting S-101 to injection and the potential for additional injection wells. Recovery in this development block was estimated to reach 31% of the oil initially in place. S-101 will be converted to injection in the second quarter of 2001. Several bottom hole locations were evaluated for the North of Crest development. The optimal configuration was determined to be a three well development with a pre- produced injector. The North of Crest development will use vertical fracture stimulated wells to access both the C and A sands. A vertical well provides access to both sands 16/40 Aurora Pool Rules and Area t,.~ ction Order 6/15/2001 while avoiding complications with faults that could hinder horizontal wells in this portion of the field. A GOC in this section of the field may be encountered at 6631 feet tvdss based on offset wells. Ultimate recovery is estimated to be approximately 35% in this area of the pool. Phase II Development Phase II of Aurora development is expected to involve six to eight producers and three to four injectors. Locations and spacing will be dependent on further reservoir simulation and evaluation of production data from Phase I development. The phased drilling program will target portions of the reservoir in the crest, along the eastern flank, and in the Beechey Block area. An approximate six well drilling program is expected to commence in 2001 that will determine additional well placements for completion of Phase II development. Well Spacing The V-200 fault block will utilize horizontal wells initially spaced at 480 acres in irregular patterns. Further infill drilling will be evaluated based on production performance and surveillance data. In the North of Crest, the Phase I vertical well spacing is expected to be approximately 120 acres per well. Infill drilling or peripheral drilling may be justified at some point of development. To allow for flexibility in developing the Aurora Pool, a minimum well spacing of 80 acres is requested. · Reservoir Management Strategy Pressure support prior to waterflood start-up will be provided from aquifer support and a gas cap, where present. Once water injection begins, the voidage replacement ratio (VRR) will exceed 1.0 to restore reservoir pressure. Once the reservoir pressure has been restored, a balanced VRR will be maintained for pressure support. The objective of the Aurora reservoir management strategy is to operate the field in a manner that will achieve the maximum ultimate recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached 17/40 Aurora Pool Rules and Area ~ .on Order 611512001 as a dynamic process. The initial strategy is derived from model studies and limited well test information. Development well results and reservoir surveillance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Aurora Pool will continue to be evaluated throughout reservoir life. Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Aurora Pool. Development will take place in two distinct phases. The first phase will use three horizontal wells to develop the V-200 Block and three vertical wells to develop the North of Crest area. Phase II will develop the remainder of the field. Peak production rates are expected to be 14,000 - 17,000 bopd. Upon waterflooding commencement, peak injection rates will be 20,000- 30,000 bwpd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. 18/40 Aurora Pool Rules and Area l~.a,zction Order 6/i 5/2001 III. Facilities General Overview Aurora wells will be drilled from an existing IPA drill site, S-Pad, and will utilize existing IPA pad facilities and pipelines to produce Aurora reservoir fluids to Gathering Center 2 (GC2) for processing and shipment to Pump Station No. 1 (PS1). Aurora fluids will be 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. The GC2 production facilities to be used include separating and processing equipment, inlet manifold and related piping, flare system, and on-site water disposal. IPA field facilities that will be used include a 24" low-pressure large diameter flowline, a 10" gas lift supply line, and a 14" water injection supply line. An 8" MI supply line from GC2 to S-Pad could be utilized for future EOR applications. The oil sales line from GC2 to PS 1 and the power distribution and generation facilities will be utilized. Exhibit 111-1 is a flow diagram of the proposed Aurora Facilities at S-Pad and Exhibit 11I-2 is an area map showing locations of the pad facilities that will be used for Aurora development. Drill Sites, Pads, and Roads S-Pad has been chosen for the surface location of Aurora wells to reach the expected extent of the reservoir while minimizing new gravel placement, minimizing well step out and allowing the use of existing facilities. Wells will primarily be drilled west and north of the existing IPA wells. An expansion of the existing pad size to accommodate additional wells at S-pad was completed in April, 2000. A schematic of the drill site layout is shown in Exhibit 111-2. No new pipelines are planned for development of the Aurora reservoir. Aurora production will be routed to GC2 via the existing S-Pad low-pressure large diameter flowline. No new roads or roadwork will be required. 19/40 Aurora Pool Rules and Areal don Order · 6/1512001 Pad Facilities and Operations A trunk and lateral production manifold capable of accommodating up to 20 new Aurora wells will be built as an extension to an existing S-Pad manifold system. A schematic showing the surface well tie-ins is shown in Exhibit III-2. Water for waterflood operations will be obtained from an extension to an existing 6" water injection supply line at S-Pad. Preliminary estimates indicate the line is sufficient to deliver water to Aurora injection 'wells at a rate of 28,000 bpd and a pressure of approximately 2000 - 2100 psig. Should current water injection pressures be insufficient, injection pressure can be boosted locally. An upgrade of the existing S-Pad power system should not be necessary for additional water injection booster pumps. Artificial lift gas will be obtained from the existing 10" gas lift supply line at S-Pad. Preliminary estimates indicate that the line is sufficient to deliver gas to Aurora production wells at a rate of 30 mmscfd and a pressure of approximately 1800 psig. All well control will be performed manually by a pad operator. Exceptions to this are the automatic well safety systems and the pad emergency shutdown system that can be triggered either manually or automatically. Production allocation is addressed in Section V. Production allocation for the Aurora reservoir currently is based upon the Interim Metering Plan (approved November 15, 2000). The plan requires a minimum of two well tests per month through the S-Pad test separator for each Aurora well. Daily production is based on straight-line interpolation between valid well tests. The total volume of production from the Aurora reservoir is designated an allocation factor of 1.0. Well pad data gathering will be performed both manually and automatically. The data gathering system (SCADA) will be expanded to accommodate the Aurora wells and drill site equipment. The SCADA system will continuously monitor the flowing status, pressures, and temperature of the producing wells. These data will be under the well pad operator's supervision through his monitoring station. 20/40 Aurora Pool Rules and Area l,.,_,.tion Order 6/15/2001 Production Center No modifications to the GC2 production center will be required to process Aurora production. GC2 was built to process a nominal oil rate of 400 mbopd, gas rate of 320 mmscfd (modifications have increased this to 1,200 mmscfd) and a nominal produced water rate of 280 mbwpd. Production, including that from the Aurora Reservoir, is not expected to exceed existing GC2 capacity. 21/40 Aurora Pool Rules and Area in~..,on Order 6/15/2001 IV. Well Operations Drilling and Well Design A number of wells have been drilled into the Aurora accumulation. Several exploration wells were drilled approximately 30 years ago. However, only the recently drilled S-100, S-101, S-102, S-103, S-104, and S-105 are currently completed in the Kupamk Formation. Many Prudhoe Bay Unit wells were logged across the Kuparuk Formation while drilling to the Ivishak Formation. However, until recently, the Kupamk Formation was not definitively tested. In February 1999, the Aurora V-200 appraisal well was drilled off an ice pad and tested at 1900 bopd. After proving the commerciality of the Aurora Oil Pool, the V-200 well was plugged and abandoned with plans to develop the Aurora Oil Pool using existing facilities at S-Pad. More recently, the PBU Ivishak S- 24Ai well was logged and a fluid sample in the Kuparuk obtained in May 1999. The S- 24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. At the present time the Aurora accumulation is being produced under Tract Operations from three wells completed in the Kupamk Formation. Three additional wells have been drilled and will be completed shortly. Approximately fifteen (15) to nineteen (20) production and injection are forecasted for the Aurora development. Aurora development wells will be directionally drilled from S-Pad utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in other North Slope fields. A 20-inch conductor casing will be set 80 feet below pad level and cemented to surface. Consideration will be given to driving or jetting the 20-inch conductor as an alternative setting method. A diverter system meeting AOGCC requirements will be installed on the conductor. Surface hole would be drilled no shallower than 2300 ft. tvdss. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle-build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous PBU wells. Cementing and casing requirements similar to other North Slope fields have been been adopted for Aurora. 22/40 Aurora Pool Rules and Area ,j~,:tion Order 6115/2001 The casing head and a blowout-preventer stack will be installed onto the surface casing and tested consistent with AOGCC requirements. The production hole will be drilled below surface casing to the Kuparuk Formation, allowing sufficient rathole to facilitate logging. Production casing will be set and cemented. Production liners will be used as needed, to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells, such as high departure wells. To date, no significant H2S has been detected in the Kuparuk Formation while drilling PBU wells nor in any Aurora wells drilled to-date. However, with planned waterflood operations, there is potential of generating H2S over the life of the field. Consequently, H2S gas drilling practices will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellsite. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. Well Design and Completions Both horizontal and vertical wells are anticipated at Aurora. The horizontal well completions could be perforated casing, slotted liner, or a combination of both. All vertical wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8 to 5-1/2 inches, depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Aurora wells. 23/40 Aurora Pool Rules and Area i. ,ion Order 6/1512001 The following table indicates casing and tubing sizes for proposed Aurora well designs. Surface Inter / Prod Casing Production Production Casing Liner Tubing Vertical 12-1/4" to 7" 9-5/8" to 4-1/2" 5-1/2" to 2-7/8" 5-1/2" to 2-3/8" Horizontal 12-1/4" to 7" 9-5/8" to 4-1/2" 5-1/2" to 2-7/8" 5-1/2" to 2-3/8" Plans are to run L-80 casing in the Aurora wells. Tubing strings will be completed with either 13-Cr 9-Cr/1Moly, or with L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/1Moly, which is compatible with both L-80 and 13-Cr. Proposed' wells will be completed in a single zone (Kupamk Formation), or multi-zone (Kupamk and Schrader Bluff, or Kupamk and Sag/Ivishak) utilizing a single string and multiple packers as necessary. As shown in the typical well schematics, Exhibit IV-1 for a vertical well and Exhibit IV-2 for a horizontal well, and Exhibit IV-3 for a multi-zone well, the wells have gas lift mandrels to provide flexibility for artificial lift or commingled production and injection. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Any completions which vary from those specified in State regulations will be brought before the commission on a case by case basis. The Aurora Owners may utilize surplus IPA wells for development, provided they meet Aurora needs and contain adequate cement integrity. Initial Development The Aurora depletion plan consists of drilling six development wells under Phase I development. The S-100, S-101i and S-102 wells, an injector and two producers, are horizontal completions drilled on the west side of the N-S trending fault (V-200 Fault Block Area). Three other wells, S-103, S-104i and S-105, a multi-zone injector and two producers, are vertical completions drilled in the North of Crest area on the east side of the N-S trending fault. Injectors are being pre-produced prior to converting to permanent 24/40 Aurora Pool Rules and Area ~.jcction Order 6/15/2001 injection. Production from these wells will be used to evaluate the reservoir's productivity and pressure response, enabling refinement of current reservoir models and depletion plans. Current modeling suggests that the V-200 Block pre-produced injection well can be converted to injection service after six months to twelve months of primary production without jeopardizing ultimate recovery in the V-200 Block. A structure map showing the V-200 Block is shown in Exhibit I-2. In the S-100, S-101i and S-102 Phase I development wells, LWD/MWD logging was conducted after top setting the 7" intermediate casing. Plans are to set the 7" intermediate casing in the top 10-50 ft. MD (0-30 feet sstvd) of the Kuparuk Formation. The MWD will include measurement of drilling parameters such as weight on bit, rate of penetration, inclination angle, etc. LWD will include GR/Resistivity and Density and Neutron porosity throughout the build and horizontal sections. A 10-11 ppg freshwater low-solids non-dispersed mud system or equivalent will be used to drill the production hole down to the 7" casing point. The mud system parameters will be optimized to minimize mud filtrate loss before drilling the 6-1/8" horizontal section. After drilling the 6-1/8" horizontal hole, 'a 4-1/2" slotted or solid liner will be run, cemented and perforated as necessary Subsurface Safety Valves There is no requirement for subsUrface safety valves (SSSVs) in Aurora wells under the applicable regulation, 20 AAC 25.265. Moreover, in light of developments in oil field technology and controls and experience in operating in the arctic environment, the Commission has eliminated blanket SSSV requirements from both rules governing both the Prudhoe Oil Pool and the Kuparuk River Oil Pool. See Conservation Orders 363 and 348, respectively. However, Rule 5 of Conservation Order 98A appears to require subsurface safety valves for Aurora wells. Therefore, the applicants recommend removal of the Aurora Oil Pool 25/40 Aurora Pool Rules and Area lnjL-c.on Order 6/15/2001 from its scope. 1( Removing the SSSV requirement would be consistent with other PBU operations. Existing completions are equipped with SSSV nipples, should the need arise to install subsurface storm chokes or pressure operated safety valves for future MI service. Surface Safety Valves Surface safety valves are included in the wellhead equipment. These devices can be activated by high and low pressure sensing equipment and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded. Testing of SSVs will be in accordance with AOGCC requirements. Drilling Fluids In order to minimize skin damage from drilling and to maintain shale stability, water- based KC1 mud may be used to drill through the Kuparuk Formation at Aurora. Freshwater low solids, non-dispersed fluids will be used to drill upper sections of each well. Stimulation Methods Stimulation to enhance production or injection capability is an option for Aurora wells. There was evidence of formation damage caused by drilling and completion fluids in the V-200 well. Consequently, the need for fracture stimulation is possible. It may also be necessary to stimulate the horizontal wells, depending upon well performance. Reservoir Surveillance Program Reservoir surveillance data will be collected to monitor reservoir performance and define reservoir properties. ~ Most of the area governed originally by CO 98A was removed in 1981, when Conservation Order 173, the Kuparuk River Field, Kuparuk River Oil Pool Rules were adopted. 26/40 ( Aurora Pool Rules and Area Injection Order 6/15/2001 Reservoir Pressure Measurements An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 6,700 ft. tvdss. An initial static reservoir pressure will be measured prior to production in at least one well for each fault block. Additionally, a minimum of two pressure surveys will be obtained annually for the Aurora accumulation, one on the east side and one on the west side of the N-S dividing fault. These will consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. It is anticipated that the operator will collect more than two pressure measurements per year during initial field development due to field complexity and fewer as the development matures. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, may be periodically run to help determine reservoir performance (i.e., production profile and injection profile evaluations). Surveillance logs will be run on multi-zone completions to assist in the allocation of flow splits as necessary. 27/40 Aurora Pool Rules and Area Injection Order 6/15/2001 V. Production Allocation Aurora production allocation will be done according to the PBU Western Satellite Production Metering Plan. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor will be applied to adjust the total Aurora production. A minimum of two well tests per month will be used to tune the performance curves, and to verify system performance. No NGLs will be allocated to Aurora. To support implementation of this procedure, several improvements to the WOA allocation system have been initiated. Conversion of all well test separators in the GC-2 area to two-phase operation with a coriolis meter on the liquid leg is expected to be completed mid-2001. The test bank meters at GC-1 and GC-2 have been upgraded as part of the leak detection system and a methodology for generating and checking performance curves for each well has been developed. Modifications to the automation system are expected to be completed mid-2001. Until the upgraded metering and allocation system for the WOA is ready for implementation, Aurora wells will use an interim metering and allocation plan based on a minimum of two well tests per month with linear interpolation and a fixed allocation factor of 1.0. We request Commission approval under 20 AAC 25.215(a) that the Aurora metering either exceeds the requirement for monthly well tests or is an acceptable alternative. 28/40 Aurora Pool Rules and Area Injection Order 6/15/2001 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection to enhance recovery from the Aurora Oil Pool. This section addresses the specific requirements of 20 AAC 25.402(c). Plat of Project Area 20 AAC 25.402(c)(1) Exhibit I-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Aurora Oil Pool as of April 1, 2001. Specific approvals for any new injection wells or existing wells to be convened to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. Operators/Surface Owners 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) BP Exploration (Alaska) Inc. is the designated operator of the Aurora Participating Area. Surface Owners within a one-quarter mile radius and inclusive of the Aurora Participating Area are as followings: State of Alaska Department of Natural Resources Attn: Dr. Mark Myers P.O. Box 107034 Anchorage, AK 99510 Pursuant to 20 AAC 25.402(c)(3), Exhibit V-1 is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area of and included within the Aurora Participated Area have been provided a copy of this application for injection. Description of Operation 20 AAC 25.402(c)(4) Development plans for the Aurora Oil Pool are described in Section II of this application. 29/40 Aurora Pool Rules and Area Injection Order 611512001 Drillsite facilities and operations are described in Section III. Geologic Information 20 AAC 25.402(c)(6) The Geology of the Aurora Oil Pool is described in Section I of this application. Injection Well Casing Information 20 AAC 25.402(c)(8) The S-101 well and S-104i well will be converted to injection service for the Aurora Oil Pool Enhanced Recovery Project. The casing program for wells S-101 and S-104i was permitted and completed in accordance with 20 AAC 25.030. Exhibit IV-2 and IV-3 details the completion for the S-101 well and the S-104i well respectively. A cement bond log indicates good cement bond across and above the Kupamk River Formation in S-104i; whereas further logging will be necessary to confirm cement integrity in S-101. Conversion of the S-101 well and the S-104i well will be conducted in accordance with 20 AAC 25.412. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. All drilling and production operations will follow approved operating practices regarding the presence of H2S in accordance with 20 AAC 25.065. Injection Fluids 20 AAC 25.402(c)(9) Type of Fluid/Source The Aurora Enhanced Recovery Project will utilize GC2 produced water as the water source. 30/40 Aurora Pool Rules and Area Injection Order 6/1512001 Composition The composition of produced water from GC2 and the Aurora Oil Pool is shown in Exhibits VI-4. The composition of Aurora produced water will be a mixture of connate water and injection water. Maximum Injected Rate Maximum water injection requirements at Aurora Oil Pool are estimated at 20,000 to 30,000 BWPD. Compatibility with Formation and Confining Zones Core, log and pressure-buildup analysis indicate no significant problems with clay swelling or compatibility with in-situ fluids. Analysis of the S-104i core indicates relatively low clay content (5-35% by volume), primarily in the form of illite. Petrographic modal analysis indicates that clay volumes in the better quality sand sections (>20 md) are in the range of 3 - 6%. Clay volumes increase to approximately 6 - 12% in the rocks with permeabilities in the range of 10 - 20 md. Below 10 md clay volumes increase to a range of 12 - 20%. Most of the identified clay is present as intergranular matrix and is detrital in origin, having been intermixed with the sand through burrowing. The level of clay diagenesis is uncertain at this time, but is expected to include some grain coating illite. The overall clay composition is believed to be mostly illitic. No diagenetic kaolinite or chlorite was reported during petrographic analysis. Illitic clays are susceptible to damage in contact with low ionic strength (i.e. fresh) filtrates and treatment fluids. The damaged clays often become dispersed and are therefore potentially migratory with fluid movement. Fluids with ionic strength (salinity) equal to 2% KC1 or greater should not pose a significant risk for damage. Further, the better quality rock types will have the least amount of clay and take most of the introduced fluids. As such, no significant clay-related formation damage is anticipated as long as adequate salinity is maintained. 31/40 Aurora Pool Rules and Area Injection Order 6/15/2001 The presence of iron-bearing minerals suggests that the use of strong acids should be avoided in breakdown treatments, spacers, etc. Geochemical modeling results indicate that a combination of GC2 produced water and connate water is likely to form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Scale precipitation will be controlled using scale inhibition methods similar to those used at Kuparuk River Unit and Milne Point. Injection Pressures 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 1800 psig. The estimated maximum surface injection pressure for the Aurora Oil Pool Enhanced Recovery Project is 3000 psig. The resulting bottom hole pressure will be limited by hydraulic pressure losses in the well tubing, with a maximum expected bottom hole pressure of 6000 psig. Fracture Information 20 AAC 25.402(c)(11) The expected maximum injection pressure for the Aurora Oil Pool Enhanced Recovery Project wells will not initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. There is no evidence of injection out of zone for similar Kuparuk River Formation waterflood operations on the North Slope. Freshwater Strata There are no freshwater strata in the area of issue (see Section N of the Application for Modification to Area Injection Order No. 4, dated April 5, 1993). Additionally, calculations of water salinity from open hole resistivity logs acquired in the Prudhoe Bay E-16 indicate a salinity range of 40,000 to 45,000 ppm for Cretaceous and Tertiary sands above the Kuparuk River Formation. Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with 32/40 Aurora Pool Rules and Area Injection Order 6115/2001 freshwater strata. Enhanced Recovery Water injection operations at the Aurora Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Fracture propagation models confirm that injection above the parting pressure will not exceed the integrity of the confining zone. The Kupamk River Formation at the Aurora Oil Pool is overlain by the Kalubik and HRZ shales, which have a combined thickness of approximately 110 feet. The HRZ is a thick shale sequence, which tends to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones of the Kuparuk River Formation. Mechanical properties determined from log and core data for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. A leakoff test was conducted in well S-101 to determine the formation breakdown pressure at the Aurora Oil Pool and that test suggested a fracture gradient of 0.73 psi/ft at initial reservoir conditions. This data agrees with data from offset fields containing wells completed in the Kupamk River Formation. The Kupamk River Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of approximately 0.85 psi/ft. In addition, rock mechanics calculations and data from the Prudhoe Bay Oil Pool indicate that sandstone fracture gradients are reduced during waterflooding operations due to reduced in-sku rock stress associated with the injection of water that is colder than the reservoir. Produced water from GC2 would have limited impact on the fracture gradient because the water temperature would be close to the reservoir temperature. 33/40 Aurora Pool Rules and Area Injection Order 6/15/2001 Hydrocarbon Recovery 20 AAC 25.402(c)(14) The Aurora Oil Pool is estimated to have original oil in place of 110 to 146 MMSTB. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15 to 25% of the original oil in place, relative to primary depletion. 34/40 Aurora Pool Rules and Area Injection Order 6/15/2001 VII. Proposed Aurora Oil Pool Rules BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that the Commission repeal Conservation Order 98A or remove the Aurora Oil Pool from its scope and adopt the following Pool Rules for the Aurora Oil Pool: Subject to the rules below and statewide requirements, production from the Aurora Oil Pool, as herein defined, may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. Rule 1: Field and Pool Name The field is the Prudhoe Bay Field and the pool is the Aurora Pool. The Aurora Pool is classified as an Oil Pool. Rule 2: Pool Definition The Aurora Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 6858.5 and 7253.5 feet in the PBU V-200 well within the following area: Umiat Meridian TllN-R12E: Sec 3:N1/2 T12N-R12E: Sec 17: S1/2; Sec 18: SE1/4; Sec 19: El/2; Sec 20: All; Sec 21: All; Sec 22: W1/2NW1/4,S1/2; Sec 23: SW1/4; Sec 25: SW1/4; Sec 26- 28: All; Sec 29: N1/2,SE1/4; Sec 32: El/2; Sec 33 - 35: All; Sec 36: N1/2,SW1/4 Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer to 500 feet to an external boundary where ownership changes. Rule 4: Automatic Shut-In Equipment (a) All wells capable of unassisted flow of hydrocarbons will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a fail-safe automatic surface safety valve. (c) Surface safety valves will be tested in accordance with Commission requirements. Rule 5: Common Production Facilities and Surface Commingling (a) The PBU Western Satellite Metering Plan satisfies the well testing requirements of 20 AAC 25.230 and 20 AAC 25.275. 35/40 Aurora Pool Rules and Area lnj uon Order 6/! 5/2001 (b) Each producing Aurora well will be tested and production will be allocated in accordance with the Prudhoe Bay Unit Western Satellite Metering Plan. (c) Allocated production for Aurora will be adjusted in conjunction with the GC-2 allocation factors. (d) Until the Prudhoe Bay Unit Western Satellite Metering Plan is implemented, the operator shall submit monthly reports containing daily allocation and well test data for agency surveillance and evaluation. During this period, each producing Aurora well will be tested a minimum of two times per month with production allocated by straight-line interpolation between well tests. The Aurora allocation factor will be 1.0 Rule 6: Reservoir Pressure Monitor.lng (a) A minimum of two pressure surveys will be taken annually for the Aurora Pool. (b) The reservoir pressure datum will be 6700 feet true vertical depth subsea. (c) Pressure surveys may consist of stabilized static pressure measurements at bottom- hole or extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. (d) Data and results from pressure surveys shall be reported annually. (e) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Rule 7: Gas-Oil Ratio Exemption Wells producing from the Aurora Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 8: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 2500 psi at the datum or within eighteen months of initial production. Rule 9: Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: 1. Summary of produced and injected fluids. 2. Summary of reservoir pressure analyses within the pool. 3. Results of well allocation and test evaluation for Rule 7 and any other special monitoring. 4. Future development plan. The report will be submitted to the state by April 1 st each year. Rule 10: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does 36/40 Aurora Pool Rules and Area Injection Order 6/15/2001 not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 37/40 Aurora Pool Rules and Area Injection Order 6/15/2001 VIII. Area Injection Application BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Aurora Pool and consider the following rules to govem such activity: Affected Area: TllN-R12E: Sec 3:N1/2 T12N-R12E: Sec 17: S1/2; Sec 18: S. E1/4; Sec 19: El/2; Sec 20: All; Sec 21: All; Sec 22: W1/2NWl/4,S1/2; Sec 23: SW1/4; Sec 25: SW1/4; Sec 26- 28: All; Sec 29: N1/2,SE1/4; Sec 32: El/2; Sec 33 - 35: All; Sec 36: N1/2,SW1/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to, and correlate with, the interval between the measured depths of 6858 and 7252 feet in the PBU V-200 well. Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been 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. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 6 below. Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity 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. A test surface pressure of 1500 psi or 0.25 psi/ft, multiplied 38/40 Aurora Pool Rules and Area Injection Order 6/15/2001 by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength will be used. The test pressure must show a stabilizing trend and must not decline more than 10% in a thirty-minute period. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever operating pressure observations, injection rates, or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Notification The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State of Federal agency remain the Operators' responsibility. Rule 9: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above 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 an increased risk of fluid movement into an underground source of drinking water (USDW). 39/40 Aurora Pool Rules and Area lnjecuon Order 6/1512001 IX. List of Exhibits I-1 I-2 I-3 1-4 1-5 1-6 1-7 1-8 1-9 1-10 1-11 1-12 1-13 II-1 11-2 II-3 11-4 11-5 11-6 III-1 111-2 IV-1 IV-2 IV-3 IV-4 V-1 Aurora Pool Location Map Top Structure Map Aurora Participating Area (APA) Type Log for Aurora Pool Aurora Areas Structural Cross Section Dip Seismic Cross Section Strike Seismic Cross Section Fluid Contacts Net C4/C3B sand Map Net C3A/C 1 Sand Map Net A Sand Map Net Hydrocarbon Pore Foot Map Model Layering and Properties Aurora Fluid Properties PVT Properties Production and Recovery Profiles for Primary Depletion Production and Recovery Profiles for Water Injection Porosity vs Permeability Aurora Well Tie-ins - Northern S-Pad Aurora Facility Location Typical Vertical Completion Typical Horizontal Completion Schrader-Kuparuk Injection Well Aurora and GC2 Water Properties Affidavit 40/40 Exhibit I- 1: Aurora Pool Location Map SANDPIPER UNIT L MIi,&iE~POINT UNIT COLVILLE RIVER UNIT i~' 'J ~" ~ i ' ',, ,,~.~ -----.-__.~._~. .~ ,~N~mSTAR UNIT r-- - ';~.~'~ ' ~ ~ T ' ----r ' ,_,~__~_.~_~ .'"-;::';~,'~:.,'&.~ --- i~----,.,' ~ 1 t- ' --! DUCK ISLAND UNIT ~ ~¢' , I L · . ~? - T '-- h'~', - ~ , ___._.~ ,'-.. F~ ! ~ ~, '~-'~.-c~? .~-~ ,.,& .... ~ ~.' '.,. - ' ~- - J ' J '-, ! ' ,-. - --J KUPARUK RIVER UNIT "--'L. PRUDHOE BAY UNIT , I BPXA CartoaraDhv/4-12-2001Am14369 .don Exhibit I-2: Top Structure Map EXHIBIT I-3 AURORA PARTICIPATING AREA (APA) ADL!282541 i , I ADL28253 i I I ADLi385193 ! ) i i , ~8 ..L7 _i ~6 ~5 I~ I 19 ,~ 20 I ~ :~ 22 23 I Expansion I Exp I Area 4 Area 3 I i- - t0 : __29I 28 -- --. APA I ADL 28259 I ' ADL 28258 ADL 28257 I IExpansion ~ Expansion[Area 1 T12N-R12E I Area 2 ..... ADL~ 47450ADL: 2826~ ~ .............. EXhibit I-5' Aurora Areas Beechey Block North oi Crest Block Block Exhibit I-6: Structural Cross Section A Exhibit I-7: Dip Seismic Section Beec~y Pt #! VS!00 803 S-16 A~ Bluff Kuparuk B Exhibit I-8' Strike Seismic Section g~ Schrader Bluff Kapamk Exhibit I-9: Fluid Contacts Contact Beechey Block V-200 Block Crestal Block GOC 6678' tvdss Per 6631' tvdss (Beechey Pt St #1) Beechey Block (S-16) WOC 6835' tvdss 6824' tvdss 6812' tvdss (Beechey Pt St #2) (V-200) (N Kup 26-12-12) Exhibit 1-10' Net C4/C3B Sand Map I Exhibit I-11' Net C3A/C1 Sand Map RURORR FIELD I KUPARUK CBR*C! Exhibit 1-12: Net A Sand Map KUPRRUK R Exhibit 1-13: Net Hydrocarbon Pore Foot Map PBU Bo~ PA Boundow i ® F~'~o se One l TOTRL KUPRRUK Exhibit II-1: Model Layering and Properties Average Pr )perties by Simulation Layer Layer Zone Porosity 13ermeability Gross Net Pay Initial (%) (md) Thickness (ft) Water Sat (ft) (%) *3 *3 *1 *2 *2 1 C4B 21 59 13 4 45 2 C4A 25 158 24 22 30 3 C3B 19 12 21 18 36 4 C1 19 42 15 7 60 5 A5 16 29 20 9 66 * 1 Based upon stratigraphic formation marker picks. *2 Based upon Aurora Log Model. *3 Based on routine core data. Exhibit II-2: Aurora Fluid Properties Initial Reservoir Pressure at 6700' tvdss Bubble Point Pressure Reservoir Temperature Oil Gravity Reservoir Oil Viscosity Reservoir Water Viscosity Reservoir Gas Viscosity Solution Gas/Oil Ratio (Rs) Oil Formation Volume Factor (Bo) Water Formation Volume Factor (Bw) Gas Formation Volume Factor (Bg) 3433 psia 3433 psia 150° F 25° - 30°API 0.722 cp 0.45 cp 0.022 cp 717 SCF/STB 1.345 RBL/STB 1.03 RBL/STB 0.843 RBL/MSCF Exhibit II-3: PVT Properties .pressure ..... BO ........ Bg ........... Oi! ..... Gas .... S°lution ........... ~s~!g ............ Rb,F.,S.~B ........ Rb~,~,~,c,~.,, ,~,!?,~,O~i~,, ,,.,v,,i~..,°..~i,t,~ ............... ~.~ cp cp scf/STB 3464 1.345 0.722 717 31 oo 1.316 0.843 0.744 0.022! 644 , 2750 1.289 0.945 0.789 0.020: 575 2400 1.262 1.083 0.858 0.019 508 2050 1.236 1.275 0.958 0.017 441 1700 1.210 1.554 1.100 0.016 375 1350 1.185 1.987 1.280 0.015 309 1000 1.159 2.732 1.530 0.014 24zl , , 650 1.133 4.283 1.880 0.013 177 300 1.102 9.340 2.440 0.012 105 124 1.081 21.615 2.950 0.011 61 0 1.041 4.520 0 Exhibit II-4: Production and Recovery Profiles for Primary Depletion 10 000 9,0(x) 7,000 ~ 6,ooo ~ 5,000 ()il Produc[ion 3.000 2,O00 1 ,(X)0 2000 2005 2010 2015 2020 2025 2030 20.0(X) 18,()00 16.000 14~0()0 12~000 _~ 10.000 ~ 8.000 6.(X)O 4.(~)0 2~(X)O Water Production 900 ~()0 700 600 50() 4O0 300 200 !00 20(X) 2(X)5 2010 2015 2020 2025 2030 30.OO0 25.000 20,000 I5,000 5,(X)0 Gas Pr(xJuctio~ Oil Recve y 2015 2020 2025 2030 Year 12 1(} 6 4 2 2000 2005 2010 2(X)0 2005 2010 2015 2020 2025 2030 Year Exhibit II-5: Production and Recovery Profiles for Water Injection Oil Production [ Water Production i 12.000 ~ I ,SIX) [ 4,(X)O i'-~~ stbd [-+- scffstb /'~\~~a300 103)00 8,000 4,0(X) 2,000 1,5(X) 1 900 60O 2000 2005 2010 2015 2020 2025 2030 Year 3.500 3.(X)O 2,500 1,500 1,000 50O 2(XX) 2(X)5 2010 2015 2020 2025 2030 Year 25,(X)0 ~ 20,(X)0 ~ 10,000 5 .(X)O Gas Production 40 35 ~ 30 25 ~ 20 © I0 0 ~ 2000 2005 2010 2015 2020 2025 2030 Year ()il Recovew 2000 2005 2010 2(315 2020 2025 2030 Ye~ Exhibit lib 1 Aurora Well Tie-ins- Northern S-Pad To/From Module 57 216 S-201 S I O0 0 0000000 To/From Modt~le 93 Polaris Well Aurora Well IPA Well Potential Well Piping Productioa?Fest (;as Lift Water Inj Exhibit III-2: Aurora Facility Location Production (#) Test (#) Gas Lift (#) Water (#) MI (#) Future Equipment (#) Aurora Well Existing Polaris Well tPA Welt # - Surface Satellite Equipment Injection Wa~er Line Tie-in (IPA injection well) Exhibit IV-1' Typical Vertical Completion nipple 2000' X nipple (ID=3.81Y') Conductor Casing Sugace Casing 4355' MD 3285'ssTVD < 12-1/4 hole 9 5/8 or 7-5/8 casing Tubing 4-1/2 or 3-1/2 ' Ct-80 Tbg 3 GI.M's Production Pkr, 6600' ssTVD Kuparuk C salld perfs Kuparuk A sand perfs Protlnction Casing 6900~ sstvd < 9-7/8" hole 7 or 5-l/2 ~ casing Exhibit IV-2: Typical Horizontal Completion nipple 2000' K nipple ( [D-38 XN nipple (~D-3 75") Conductor Casing ~ 20" casing Surface Casing 4355' MD 3285'ssTVD 13 1/2 hole [03/4 ol 9-SAS casing Tubing 4 l/2 ot 3-112" Cr 80 Tbg 3 GLM's Prl~tlction Pkr, - [ 0,300' MD 66 [ 8' ss'[ VD Pri~lwtion Liner 852' MD 6700 6712' sstvd 6 3/4 hole Intermediate Casing 10400' MD 6678' sstvd 9 7/8 hole 7 ~r 5 1/2" casing TREE = 4-1/8" 5M WELLHEAD:. FMC 11" ~ki~'i"~'~'"~ 3'i~:'"E~'~''~ 35.9 Datum MD = 8798 I 9-5/8"40#L-80BTCI ] 3736' Minimum ID = 3.725" @ XN nipple I Exhibit IV-3: Schrader-Kupa( "Injection Well S-104i SA FETY NOTES: AOTUA L DEPTHS WILL BE PROVIDED BEFORE COMPLETION 2403' J J X-Nipple, 3.813" ID J STA MD TVD DEV TYPE MAN LATCH GLM5 4839 3495 54 KBG-2-T/L BK GLM4 6731 4883 31 KBG-2-T/L BK GLM3 6920 5046 29 KBG-2-T/L BK SLSV 7035 5147 29 Baker CMU BK GLM2 7117 5218 30 KBG-2-T/L BK SLSV 7175 5268 30 Baker CMU BK GLM1 7266 5347 30 KBG-2-T/L BK SLSV 7333 5406 30 Baker CMU BK ~ 6842' J J 4-1/2" X, 3.813" ID J -- !sss3' I I Baker S-3, 7"x 4.5"I --?0~, ] I BakerSABL-3 I ----?=0~' ! I BakerSABL-3 I 4-1/2" 12.6#/ft L-80 J I NSCT PERFORATION SUMMARY REF LOG: Ref Platform Express GR/Res 1/27/2001 ANGLEAT TOP PERF: I 29 I Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 4.63 6 6920-6980 Open 2/4/2001 " 6 7018-7050 Open 2/4/2001 " 6 7070-7094 Open 2/4/2001 " 6 7114-7124 Open 2/4/2001 " 6 7162-7182 Open 2/4/2001 " 6 7216-7266 Open 2/4/2001 " 6 7280-7302 Open 2/4/2001 " 6 7325-7346 Open 2/4/2001 --__8679' J J Baker SABL-3 J 8703' I I 4-1/2" X, 3.813" ID J 8724' 1 j 4-1/2" XN, 3.725" ID J ~z3e, I j4-1/2"WLEG I IP~TD I I .~oo' J 7" 26# L-80 m-BTC J J 9186' DATE REV BY COMMENTS 01/08/01 P. Smith Original Proposed Completion 02/09/01 P. Smith As-Completed PRUDHOE BAY UNIT / AURORA FIELD WELL: S-104i PERMIT No: 200-196 APl No: 50-029-22988-00 Sec. 35, T12N, R12E, 4494' FEL, 633' FNL BP Exploration (Alaska) Exhibit IV-4: Aurora and GC2 Water Properties 22 2.17': 1960 ................. i~64'0~! !. ...~.~.:: .........~.~.....................: .,......:-..,~=~,.,..:.~...::..:=.=.,,:-~.~...~.:.-....: ..: ..:.......,..~ .......~.,..~,.~.:;-,,~....: .~=.,......-:~>~-_~_~.~.~?~_~-;..~:<~:.::....~- ~:~.~ ~ ~,: ,~ .. ~ ~, .:. ~,. ~,:. : - ~. ,: ~ 53:~ 247~ 10754! 12600 ~..~ .~...:::.-~ ..~..~.-:..._- :~.,....-.:? ..:_:..¢~-~.~.~ .~:=-~ ~-~.~, ~;~...~:~ ~ ~.~. ~ ....... ..~ ,.~:< ..~ ~...~ _:.. .,, ..... . ,, ~ 0.01i 4.32 :: 14~ 156! 6.67 6.9~' 821i 107' ...... ':'""~':~:~ 9020 :~ 8080:: ';,.~ .~i': :, · .?.~ ........... . .................. . .......... , .................. . ................ . .......... _ ..................... . ............................... . ....................................................... ..? ............................................. . .............. . .......... , ......... 4"-" 26.2 ~-~ 38~ 560~ 23,427 21,932! Exhibit V-1 AFFIDAVIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Gordon Pospisil, declare and affirm as follows: 1. I am the Supervisor of the Western Satellite Development for BP Exploration (Alaska) Inc., the designated operator of the Aurora Participating Area, and as such have responsibility for Aurora operations. 2. On 6//~g'/a ! , I caused copies of the Aurora Oil Pool, Pool Rules and Area Injection Application to be provided to the following surface owners and operators of all land within a quarter mile radius of the proposed injection areas: Operators: BP Exploration (Alaska) Inc. Attention: M. Cole P.O. Box 196612 Anchorage, AK 99519-6612 Surface Owners: State of Alaska Department of Natural Resources Attention: Dr. Mark Myers 550 West 7th Avenue, Suite 800 Anchorage, AK 99501-3510 Dated: Gordon Pospisil Declared and affirmed before me this 15 ~ day of "~"'lJ/td~' ~,~o~ ! . 0 'tllllll Ill[[~' Notar ubli n ~ .~ and for Alaska ! My commission expires: ~///.Y'/iiI__q #2 BP Exploration (Alaska), .Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 May 24, 2001 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 FIE: Aurora Pool Rules And Area Injection Application Dear Commissioners: Enclosed is the submission of Pool Rules and Area Injection Application for the Aurora Oil Pool. We look forward to discussing this report .with you further and setting a hearing date after the 30-day public notice period has ended. BP Exploration (Alaska) Inc., in its caPacity as Aurora Operator and Unit Operator, respectfully requests that a hearing commence as early as possible in order to gain approval of an... Area Injection Order. Facilities to begin water flood operations are expected to be available in July 2001. Please contact the authors if you have any questions or comments regarding this request. Sincerely, Gordon Pospisil GPB Satellites Manager Attachments Author Name Jim Young Ed Westergaard Bruce Weiler Gary Molinero Fred Bakun CC: Randy Frazier (BP) J. P. Johnson (PAl) Position Office Ops. Eng. 564-5754 Dev. Geologist 564-5972 Facility Eng. 564-4350 Geophysicist 564-5103 Res. Eng 564-5173 M. P. Evans (ExxonMobil) P. White (Forest Oil) Aurora Pool Rules and Area Injection Order 5/24/2001 Aurora Pool Rules And Area Injection Application May 24, 2001 1/35 ,I Aurora Pool Rules and Area Inj~c.on Order 5/24/2001 I. Geology ........................................................................................................................... 3 Introduction ..................................................................................................................... 3 Stratigraphy ..................................................................................................................... 3 Structure .......................................................................................................................... 7 Fluid Contacts ................................................................................................................. 9 Pool Limits ...................................................................................................................... 9 II. Reservoir Description and Development Planning ..................................................... 10 Rock and Fluid Properties ............................................................................................. 10 Hydrocarbons in Place .................................................................................................. 12 Reservoir Pertbrmance .................................................................................................. 12 Development Planning .................................................................................................. 14 Model Results ................................................................................................................ 15 Development Plans ........................................................................................................ 16 Reservoir Management Strategy ................................................................................... 17 III. Facilities ..................................................................................................................... 19 General Overview ......................................................................................................... 19 Drill Sites, Pads, and Roads .......................................................................................... 19 Pad Facilities and Operations ........................................................................................ 20 Production Center .......................................................................................................... 21 IV. Well Operations ......................................................................................................... 22 Drilling and Well Design .............................................................................................. 22 Reservoir Surveillance Program .................................................................................... 26 V. Production Allocation .................................................................................................. 28 VI. Area Injection Operations .......................................................................................... 29 VII. Proposed Aurora Oil Pool Rules ............................................................................... 30 VIII. Area Injection Application ....................................................................................... 33 IX. List of Exhibits ........................................................................................................... 35 2/35 Aurora Pool Rules and Area Injbc.on Order 5/24/2001 I. Geology Introduction The Aurora Pool is located on Alaska's North Slope, as illustrated in Exhibit I-1. The Aurora Pool was confirmed in 1999 by the drilling of the V-200 well. The reservoir interval for the Aurora Pool is the Kuparuk River Formation. The Aurora Pool overlies the Prudhoe Bay Unit (PBU) Sadlerochit Group reservoirs in the vicinity of S-Pad. In addition to the V-200 well, the S-100, S-101, S-102, S-103, S-104, and S-105 wells are recent Kuparuk River Formation penetrations in this area. The North Kuparuk 26-12-12 and Beechey Point State #1 wells, both drilled in 1969, were the first wells to penetrate and test hydrocarbons in the Aurora Pool. A number of PBU Sag River/Ivishak development wells also penetrated the overlying Kuparuk River Formation. The S-24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. Four S-Pad and M-Pad well penetrations and Term Well C define the southeastern limit of the Aurora accumulation. As shown in Exhibit I-2, the top of the Aurora structure crests at 6450 feet true vertical depth sub-sea (tvdss). The deepest interpreted oil-water contact (OWC) is at 6835 feet (tvdss) in the Beechey Point State # 2 well. Exhibit I-3 shows the location of the Aurora Participating Area (APA), including expansion areas identified by the Department of Natural Resources. The area encompassed by the Aurora Pool would be removed from the Prudhoe Bay Field Kuparuk River Oil Pool rules area under Conservation Order 98-A. Stratigraphy The productive interval of the Aurora Pool is the Kuparuk River Formation, informally referred to as the "Kuparuk Formation". This formation was deposited during the Early Cretaceous geologic time period, between 120 and 145 million years before present. Exhibit I-4 shows a portion of the open-hole wireline logs from the V-200 well. This "type log" illustrates the stratigraphic definition of the Aurora Pool. The log is scaled in true vertical depth subsea and also has a measured depth (md) track. In the V-200 well, the top of Kuparuk Formation occurs at 6,693 ft. tvdss (6,858.5 ft. md) and the base occurs at 7,070 ft. tvdss (7,253.5 ft. md). 3/35 Aurora Pool Rules and Area Injection Order 5/24/2001 The Kuparuk Formation was deposited as marine shoreface and offshore sediments, and is composed of very fine to medium grained quartz-rich sandstone, which is interbedded with siltstone and mudstone. The sandstones typically have higher resistivity (3-50 ohm- meters) than the surrounding lithologic units. The Kuparuk Formation base is bounded by its contact with the Early Cretaceous-age Miluveach Formation and is distinguished by a change in lithology and conventional electric log character. The Miluveach Formation is shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation top is defined by its contact with the Early Cretaceous-age Kalubik Formation or the overlying Early Cretaceous-age High Radioactive Zone (HRZ) Formation. Both are shales, and they are distinguished from the Kuparuk River Formation by a change in lithology and conventional electric log character. The Kalubik Formation is a dark gray shale with a Gamma Ray log signature of 80 to 135 API units, and the HRZ is a black, organic-rich shale with a Gamma Ray log signature typically greater than 150 gamma API units. The Kuparuk Formation in the Aurora Pool is stratigraphically complex, characterized by multiple unconformities, changes in thickness and sedimentary facies, and local diagenetic cementation. As shown on the type log in Exhibit 1-4, the Kuparuk Formation is divided into three stratigraphic intervals, from oldest to youngest, the A, B, and C intervals, with the A and C intervals divided into a number of sub-intervals. An overlying unit, called the D Shale, is locally present in the northern part of the Aurora Pool. Three unconformities affect Kuparuk thickness and stratigraphy. The Lower Cretaceous Unconformity (LCU) has erosional topography. It truncates downward and dips to the east where it successively removes the Kuparuk B and Kuparuk A intervals. The C-4 Unconformity also truncates downward to the east progressively removing the C-4A, C- 3B, C-3A, C-2, and C-1 sub-intervals before merging with the LCU. A younger unconformity, called the Pre-Aptian Unconformity also affects the Aurora Pool. At the Beechey Point wells in the western portion of the Aurora Pool, the Kuparuk Formation is 4/35 Aurora Pool Rules and Area Injection Order 5/24/2001 unaffected and the HRZ interval above this unconlbrmity is in contact with the Kalubik Formation. However, this unconformity also truncates downward to the east. At the V- 200 well and other S-Pad wells to the east, the Kalubik Formation is eroded, and the HRZ interval is in contact with the Kuparuk C-4B sub-interval. This Pre-Aptian Unconformity eventually truncates the Kuparuk C-4B and the C-4A locally, and merges with the C-4 Uncontbrmity and the Lower Cretaceous Unconformity at the eastern edge of the Aurora area. The Kuparuk A and B units have a distinctly different stratigraphic thickness trend than the Kuparuk C units. Where not truncated, the lower A unit maintains a nearly uniform thickness throughout the Aurora area, suggesting that its deposition pre-dates significant fault movement. In contrast, the thickness, lithofacies, and diagenesis of the C units are variable and have been influenced by differential erosion, and variable diagenetic fluid effects. As a result of these processes, the entire Kuparuk C interval thins south and southeastward and reservoir quality varies laterally and vertically. The lower Kuparuk A interval contains two reservoir quality sub-intervals; the A-4 and A-5 sand units, which are 30 feet and 20 feet thick, respectively. In the V-200 well, these sands are wet. In structurally higher portions of the field to the east, these A sand units are expected to be oil-bearing and productive. The A-5 sand appears to be higher quality reservoir than the A-4 sand. The overlying Kuparuk B interval is dominated by siltstone and sandy mudstone with numerous discontinuous thin sandstone lenses, the thickest of which are up to 3 feet thick. In the V-200 well, wireline logs show these thin B interval sands to be wet. The uppermost unit, the Kuparuk C interval, contains the primary reservoir sands of the Aurora Pool. The thickness of this interval 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 lithology of this upper unit is variable, consisting of interbedded very fine-grained to medium-grained sandstone with minor amounts of muddy siltstone and sandy-silty mudstone. The Kuparuk C sands are generally very quartzose and 5/35 Aurora Pool Rules and Area Inj'ectton Order 5/24/2001 moderately sorted. The Kuparuk C interval is intensely bioturbated, contributing to the heterogeneous nature of the Kuparuk C. The Kuparuk C is further subdivided into the following sub-intervals i¥om oldest to youngest: C-l, C-2, C-3A, C-3B, C-4A, and C- 4B. The C-1 overlies the Lower Cretaceous Unconformity. The Kuparuk C-1 and C-4B sub-intervals are coarser grained and contain variable amounts of glauconite and diagenetic siderite. The volume and distribution of siderite and glauconite plays an important role in the reservoir quality of the Kuparuk C-1 and C-4B intervals. These minerals are unevenly distributed and may affect a portion of the rock volume in the C-1 and C-4B sub-intervals. Due to the increase in structural clay volume, compaction, and cementation, the porosity, permeability, and productivity of these sub-intervals are reduced. The C-1 is the coarsest grained sub-interval. It is a well-sorted medium-grained sandstone with occasional coarse and very-coarse grains. The C-1 has a fairly uniform thickness of 14 feet to 18 feet except to the southeast where it thins due to truncation. The upper portion of the C-1 sub-interval gradationally fines upward into the C-2 sub- interval. The C-2 sub-interval is the finest grained unit of the Kuparuk C interval and is considered non-reservoir. In the western portion of the Aurora Pool, it is dominated by silty mudstone with occasional very fine-grained sand laminations and interbeds. In the eastern part of th Aurora, the C-2 lithology transitions to very fine-grained muddy-silty sandstone, indicating a lateral facies change I¥om west to east. The C-2 interval has a somewhat uniform thickness of 28 feet to 36 feet in the western part of the field. The C-2 thins to the southeast and is eventually truncated. The C-3A sub-interval is composed of coarsening upward sandstone beds interbedded with silty mudstone. The sandstone beds range from 1 to 2 feet thick, silty, very fine- grain sand at the base up to 10 feet thick, tine-grained sand at the top. The mudstone interbeds display lateral facies variation, similar to the underlying C-2 sub-interval, in that they coarsen eastward to silty very fine-grained sandstone toward the truncation. The overlying C-3B sub-interval is distinguishable from the underlying C-3A sub- 6/35 Aurora Pool Rules and Area Injection Order 5/24/2001 interval. The sandstones amalgamate and the mudstone interbeds are not present. The C-4A sub-interval continues the coarsening upward trend from fine-grained sandstone at the base to medium-grained sandstone toward the top. Due to the relatively coarse grain size and low volume of clay matrix, the C-4A sub-interval has the highest net to gross and reservoir quality in the Kuparuk Formation in the Aurora Pool area. The C-4A and C-4B sub-intervals are separated by an intra-formational unconformity that marks the end of the coarsening upward trend. This unconformity, called the C-4 Unconformity, is a disconformity in the western half of the accumulation. However, it truncates downward through the stratigraphic section in the eastern half of Aurora, where it eventually merges with the Lower Cretaceous Unconformity. The top portion of the C- 4B is a fining upward sequence into the overlying Kalubik Formation. C-4 interval thickness varies due to interaction by unconformities. The interval is thickest at the Beechey Point area where total C-4 thickness exceeds 60 feet. The interval thins southeastward and is eventually truncated. Structure Exhibit 1-2 is a structure map on the top of the Kuparuk Formation with a contour interval of 25 feet. Top Kuparuk structure in the Aurora area is essentially a northwest-southeast oriented ridge, which is broken up by north-south striking faults. Gentle slopes dipping 2.5 to 6.5 degrees away from the structural crest characterize the northeast and southwest flanks of the ridge. In contrast, rotated fault blocks characterize the southern and western flanks of the ridge. 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 well. The southeastern terminus of the Aurora Pool is coincident with the "Prudhoe High", a large basement-involved structural uplift that underlies the Prudhoe Bay field. Early Cretaceous and older sediments lapped over this structural high, and were later uplifted and subsequently beveled off by unconformities. Thus, this major structural high east of the Aurora accumulation is devoid of Kuparuk. The Kuparuk Formation thins 7/35 Aurora Pool Rules and Area Injecuon Order 5/24/2001 southeastward to a zero edge against the Prudhoe High. The erosional truncation is orthogonal to the northwestern orientation of the overall structural ridge As shown on Exhibit 1-5, Aurora can be divided into five structurally defined areas. (1) The Beechey Block, the westernmost area is a complexly faulted area upthrown to a major north-south fault. The Beechey Point wells were drilled in this area. (2) The V- 200 Block is a structurally stable area between the Beechey Block to the west and the north-south bisecting fault to the east. The V-200 well and the first group of horizontal development wells (S-100, S-101, S-102) penetrate this block. (3) The Crest Block is an intensely faulted area on the upthrown (eastern) side of the north-south bisecting fault. The top of the Kuparuk horizon reaches its structural crest at 6,450 ft. tvdss in the Crest Block. Ten S-Pad Sag River/Ivishak wells have penetrated the Kuparuk Formation in this block. (4) The North of Crest Block lies north of the Crest Block and east of the major north-south fault. The North Kuparuk 26-12-12 and Aurora development wells S- 103, S-104, and S-105 provide well control in this block. (5) The Eastern Block includes the area east of another north-south fault system near the S-08 and S-02 wells. This block is less structurally complex than the Crest Block and includes the southeastern thinning and truncation of the Kuparuk reservoir. Eight S-Pad Sag River/Ivishak wells penetrate the Kuparuk Formation in this block. Exhibit I-6 is a northwest-southeast oriented structural cross-section along the axis of the Aurora structural ridge (see Exhibit I-2 for location). This cross-section illustrates the effect of north-south oriented faulting as well as the eastern truncation of the Kuparuk reservoir by the three unconformities. Exhibit I-7 is a dip-oriented seismic traverse at the same northwest-southeast location as the cross section (see Exhibit I-2 for location). This exhibit shows the overlying and underlying stratigraphy as well as the fault complexity of the area. Exhibit I-8 is a strike-oriented seismic traverse from southwest to northeast (see Exhibit I-2 for location). It shows a cross view of the structural ridge that forms the Aurora Pool, and it also illustrates how fault complexity varies at different stratigraphic horizons. 8/35 , Aurora Pool Rules and Area Injecuon Order 5/24/2001 Fluid Contacts Exhibit I-9 shows the interpreted Oil/Water Contacts (OWCs) and Gas/Oil Contacts (GOCs) in the Aurora Pool. Based on wireline logs, OWCs have been interpreted in the North Kuparuk 26-12-12 well at 6812 feet tvdss and at 6835 feet tvdss in the Beechey Point State #2 well. Repeat Formation Tester (RFT) pressure gradient data in the V-200 well indicate a free water level at 6824 feet tvdss. These data suggest either a 23 feet range of OWC uncertainty or compartmentalization of the Aurora fault blocks and a westward deepening of the OWC across the Aurora area. At present a common GOC for the Aurora Pool has not been identified. Based on wireline logs, core analysis saturations, and core staining, a GOC is interpreted in the S- 16 well at 6631 feet tvdss. Based on well tests, mudlog and wireline logs, a GOC is interpreted in the Beechey Point State #1 well at 6678 feet tvdss. Sidewall core saturations and staining, and RFT pressure gradient data and fluid samples from the S-31 and S-24A wells in the Crest Block indicate oil above the GOC depths in the S-16 and Beechey Point State #1 wells. The Crest Block appears to be gas free. Pool Limits The trap for oil and gas in the Aurora Pool is created by a combination of structural and stratigraphic features. The accumulation is bounded to the west by se'veral faults where the reservoir is juxtaposed against impermeable shales of the overlying Kalubik Formation and HRZ Shale. To the southwest and north, the pool limit is defined by the down-dip intersection of the top of reservoir with the oil-water contact. To the east and southeast the reservoir is truncated by the Pre-Aptian, C-4, and Lower Cretaceo'us Unconformities. These unconformities merge at the southeastern limit of the field. The boundary of the Aurora PA, including the Expansion Areas, is within the proposed boundary of the Aurora Pool. Exhibits 1-10 through 1-12 are net sandstone maps of the Aurora Pool with a contour interval of 10 feet. Exhibit 1-13 is a net hydrocarbon pore foot map of the Aurora Pool with a contour interval of 10 feet. 9/35 Aurora Pc×)I Rules and Area Injecuon Order 5/24/2001 II. Reservoir Description and Development Planning Rock and Fluid Properties The reservoir description for the Aurora Pool is developed from the Aurora Log Model. Geolog's Multimin is used as the porosity/lithology 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 lithologic 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 #1, S-04 and S-16. Porosity and Permeability Porosity and permeability measurements .were based upon routine core analysis (air permeability with Klinkenberg correction) from the following well set: S-16, S-04, Beechey Point State #1, NWE 1-01, NWE 1-02, and NWE 2-01. The ratio of vertical to horizontal permeability (kv/kh) was 0.006 per 20 feet interval, based on the harmonic average of routine core data. Typical single plug kv/kh ratios ranged from 0.4 to 1.2. Exhibit II-1 shows values for porosity and permeability by zone that were used in the reservoir simulation. Net Pay Net pay was determined from the following criteria: minimum porosity of 15%, Vclay < 28%, and Vglauconite <40%. If the volume of siderite exceeded 30%, the net pay was discounted by a factor of 0.5. Exhibit II-1 shows gross thickness by zone based on marker picks and net pay based on the Aurora Log Model criteria. Water Saturation Water saturations for the Aurora reservoir model were derived using mercury injection capillary pressure (MICP) analyses from S-04 and S-16 core. The distribution of the data 10/35 Aurora Pool Rules and Area Inj~cuon Order 5/24/2001 was characterized using two distinct Leverett J-functions for rock with >20md and <20md permeability. The capillary pressure data were then used to initialize the Aurora reservoir model utilizing initial water saturations as shown in Exhibit II-1. Relative Permeability Relative permeability curves for Aurora were derived by comparison to analogs on the North Slope. The crude oil from Aurora was evaluated against other North Slope reservoirs. In terms of API gravity and chemical composition, the Aurora crude most closely resembles Prudhoe Bay and Pt. McIntyre crude. The Kuparuk sands within the Aurora Pool resemble two Pt. McIntyre rock sub-types, referred to as rock type #6 (for permeability >20md) and rock type #8 (permeability <20md). The relative permeability curves generated for these Pt. McIntyre rock types were employed in the Aurora reservoir model. Wettability Based on the relatively light nature of the Aurora crude and relative permeability data from the Pt. McIntyre analog, the reservoir is expected to be intermediate to water wet. Initial Pressure & Temperature Based on RFT data from V-200, the initial reservoir pressure is estimated at 3433 psia at the reservoir datum of 6700 feet tvdss. The reservoir temperature is approximately 150 degrees Fahrenheit at this datum. Fluid PVT Data Reservoir fluid PVT studies were conducted on V-200 crude from recombined surface test separator samples and RFT downhole samples. The reservoir pressure was 3433 psia at 6700 feet tvdss (datum). The API gravity was 29.1° with a solution gas oil ratio (GOR) of 717 sclTstb. The formation volume factor was 1.345 RVB/STB and the oil viscosity was 0.722 centipoise at reservoir pressure and temperature. The bubble point for Aurora crude varied according to the sampling method. RFT samples from V-200 had bubble points ranging from 3028 psig to 3590 psig. This dispersion is most likely 11/35 Aurora Pool Rules and Area Injecuon Order 5/24/2001 due to the sampling process. The recombined surface samples had a bubble point of 3073 psig. Exhibit II-2 shows a summary of the fluid properties for the Aurora accumulation. Exhibit II-3 contains a listing of PVT properties as a function of pressure. 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. Formation gas in place ranges from 75 to 100 bscf, and gas cap gas ranges from 15 to 75 bscf. Reservoir Performance Well Performance Eight wells have been tested in the Kuparuk formation at Aurora. Five of the test wells (Beechey Point State #1, Beechey Point State #2, North Kuparuk 26-12-12, V-200, and S-24Ai) are unavailable for Aurora production. Six development wells have been completed and tested in the Kuparuk (S-100, S-101, S-102, S-103, S-104 and S-105). The Beechey Point State #1 well was tested twice, producing 1334 mmscfd gas (17.8 bopd condensate) and 2700 mmscfd gas. A GOC pick was not clearly defined, but based on interpreted wireline log and test data the GOC is possibly at 6678 feet tvdss, but could range from 6648 feet tvdss to 6705 feet tvdss. Pressure buildup analysis indicates that the Kuparuk sands were badly damaged with a skin in excess of +50. In Beechey Point State #2, an attempt to test the Kuparuk horizon was made, but the formation would not flow. It is suspected that the Kuparuk sands were badly damaged during drilling based on the high skin from Beechey Point State #1. An OWC is interpreted at 6835 feet tvdss from sidewall core data and logs. The North Kuparuk 26-12-12 well had three flow teSts performed in the Kuparuk. The first produced 8 bbls of oil over 2-6 hours, the second produced 32 bopd, and the third 28 bopd. An OWC was interpreted at 6812 feet tvdss from logs. Oil API gravity ranged 12/35 Aurora Pool Rules and Area In jet.on Order 5/24/2001 t¥om 25.2 to 26.4 degrees. The V-200 encountered oil in the Kuparuk and a free water level was calculated from RFT pressure data at 6824 feet tvdss. The V-200 was tested in four stages while progressively adding perforations uphole. The initial test, with perforations at 6900 - 6920 feet MD, tested at 387 bopd with a GOR of 541 scffstb. The second production test opened an additional 20 feet of formation (6880-6920 feet MD) and tested at 1517 bopd with a GOR of 535 scf/stb from both intervals. After the second set of perforations was added, surface PVT samples were collected and a pressure transient test was performed. The third production test opened a further 18 feet of formation (6862-6920 feet MD) and tested at 1801 bopd with a GOR of 677 scffstb from all three intervals. When the well was logged, a final production test flowed at a rate of 1915 bopd with a GOR of 718 scffstb from all three intervals. The S-24Ai well was not flow tested, but RFT data were collected. The entire Kuparuk interval was oil bearing and no gas or water contact was detected. The RFT pressures and oil gradient were sufficiently different (11 psi at common tvdss) from V-200 to suggest that the S-24Ai fault block is isolated from the V-200 hult block. 'The API gravity of the RFT sample was 25.6 degrees. S-100 was drilled as a horizontal well in the V-200 fault block in Phase I of Aurora development drilling. Log analysis indicates S-100 has over 1500 feet of net pay. The well was brought on line in November 2000 and the initial well test produced 7,230 bopd at a GOR of 831 scf/stb. Initial AP1 gravity was 26°. S-101 was drilled as a horizontal well in the southern portion of the V-200 fault block as the second well of Phase I development drilling. Log analysis indicates the well has over 2500 feet of net pay. A December 2000 production test produced 1062 bopd at a GOR of 20707 scffstb. Well logs suggest a possible GOC in the toe of the well at =6680 feet tvdss. Initial APl gravity was 47°. The elevated AP1 was due to the production of gas condensate liquids. S-102 was drilled as a horizontal well in the northern portion of the V-200 fault block as 13/35 Aurora Pool Rules and Area Injecuon Order 5/24/2001 the third well of Phase I development drilling. Log analysis indicates that the well has approximately 400 feet of net pay and that the reservoir is of considerably lower quality than for the S-100 and S-101 wells. A December 2000 test produced 458 bopd at a GOR of 12005 scf/stb. Initial API gravity was 26°. Aquifer Influx The aquifer to the north of Aurora could provide pressure support during field development. Early production data from the flanks of the field will be evaluated to determine the extent of pressure support. Current modeling efforts, both with and without a Fetkovich aquifer, do not significantly change injector requirements or location. As production data become available this assessment could change. Gas Coning / Under-Running Log and RFT data were integrated with the Aurora structure map to identify free gas in the Aurora Pool. It is likely that there are three to five small discrete gas caps located throughout the accumulation. Beechey Point State #1 logs suggest a GOC at 6678 feet tvdss in the western portion of the Aurora Pool. Sidewall core from S-31 and RFT fluid samples from S-24Ai in the central portion of the accumulation suggest that this fault block is filled with oil to the crest of the structure. Log and core data from S-16 indicate the Eastern Block may have a GOC at 6631 feet tvdss. Initial production from development wells may produce gas cap gas through coning or under-mn mechanisms. This gas volume could impact early well performance, but the effect should dissipate as the small gas caps are produced and pressure maintenance is initiated. The current depletion plan is to produce any associated gas, while evaluating well work options. As production and reservoir surveillance data become available, this interpretation could alter substantially. Development Planning A reservoir model of the Aurora Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles. 14/35 Aurora Pool Rules and Area Inj~,.,~on Order 5/24/2001 Reservoir Model Construction A fine scale three-dimensional geologic model of Aurora was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk reservoir volume and distribution of porosity for the Aurora reservoir model. This reservoir model is a three-dimensional, three-phase, black oil simulator. The model area encompasses the known extent of the Aurora accumulation. The model has 300 feet by 300 feet (2.0 acre) cells. The reservoir model is defined vertically with five layers that have a nominal thickness of five to 20 feet. Exhibit II-1 shows the correspondence of model layers to geologic zones and summarizes average physical properties for each model layer. Faults and juxtaposition are honored in the model through the use of corner point geometry and non-local grid connections. Water saturations in the reservoir model were established by capillary pressure equilibrium. Two Leverett J-Curves were used for >20md and <20md rock. Oil water contacts were varied across the field from 6812 feet to 6835 feet tvdss based on available data (log, RFT, etc.) from each fault block. The reservoir pressure was set to 3433 psia at the datum of 6700 feet tvdss. Model Results Two development options were evaluated for Aurora: primary depletion and waterflood. Primary Recovery The primary recovery mechanism was a combination of solution gas drive, gas cap expansion, and aquifer support. Model results indicate that primary depletion would recover approximately 12% of the OOIP. Exhibit 11-4 shows production and recovery profiles for primary depletion. Under primary depletion, the Aurora Pool experiences a rapid decline in reservoir pressure that falls below 2000 psig by year 2006. Production rate peaks at 7000 to 9000 bopd. Waterflood Waterflood has been identified as the preferred development option for Aurora. It is 15/35 Aurora Pc×~l Rules and Area Inj¢~tmn Order 5/24/2001 anticipated that field development will require ten to thirteen producers and five to seven injectors. The reservoir simulation of waterflood reached a recovery of 34% of the OOIP with 0.50 hydrocarbon pore volume injected (HCPVI). Exhibit II-5 shows production and recovery profiles for an Aurora waterllood development. Production rate peaks at 14,000 - 17,000 bopd with a maximum water injection rate of 20,000- 30,000 bwpd. Enhanced Oil Recovery (EOR) Preliminary analysis indicates the potential for miscible gas flood in the Aurora accumulation. Early screening indicates on the order of 5% incremental oil recovery. Further evaluations need to be performed to determine the impact on total recovery. Development Plans Phase I Development Phase 1 development focuses on the V-200 Block and North of Crest Block. Several wateffiood development options were studied using the Aurora reservoir simulator. Initial studies focused on the V-200 fault block to optimize well location and producer/injector placement. The base development consists of three horizontal wells to develop and further evaluate the V-200 Block (S-100, S-101, S-102). Development drilling data indicates the presence of a gas cap at a log-interpreted depth of ~6680 feet tvdss. Simulation studies indicate recovery from the V-200 block can be optimized by converting S-101 to injection and the potential for additional injection wells. Recovery in this development block was estimated to reach 31% of the oil initially in place. S-101 will be converted to injection in the second quarter of 2001. Several bottom hole locations were evaluated for the North of Crest development. The optimal configuration was determined to be a three well development with a pre- produced injector. The North of Crest development will use vertical fracture stimulated wells to access both the C and A sands. A vertical well provides access to both sands while avoiding complications with faults that could hinder horizontal wells in this portion of the field. A GOC in this section of the field may be encountered at 6631 feet tvdss based on offset wells. Ultimate recovery is estimated to be approximately 35% in this area of the pool. 16/35 Aurora Pool Rules and Area Injecuon Order 5/24/2001 Phase II Development Phase II of Aurora development is expected to involve six to eight producers and three to four injectors. Locations and spacing will be dependent on further reservoir simulation and evaluation of production data I¥om Phase I development. The phased drilling program will target portions of the reservoir in the crest, along the eastern flank, and in the Beechey Block area. An approximate six well drilling program is expected to commence in 2001 that will determine additional well placements for completion of Phase II development. Well Spacing The V-200 fault block will utilize horizontal wells initially spaced at 480 acres in irregular patterns. Further infill drilling will be evaluated based on production performance and surveillance data. In the North of Crest, the Phase I vertical well spacing is expected to be approximately 120 acres per well. Infill drilling or peripheral drilling may be justified at some point of development. To allow for flexibility in developing the Aurora Pool, a minimum well spacing of 80 acres is requested. Reservoir Management Strategy Pressure support prior to waterflood start-up will be provided from aquifer support and a gas cap, where present. Once water injection begins, the voidage replacement ratio (VRR) will exceed 1.0 to restore reservoir pressure. Once the reservoir pressure has been restored, a balanced VRR will be maintained for pressure support. The objective of the Aurora reservoir management strategy is to operate the field in a manner that will achieve the maximum ultimate recovery consistent with good oil field engineering practices. To accomplish this objective, reservoir management is approached as a dynamic process. The initial strategy is derived from model studies and limited Well test information. Development well results and reservoir surveillance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Aurora Pool will continue to be evaluated throughout reservoir life. 17/35 Aurora Pool Rules and Area In!- .on Order 5/24/2001 Reservoir Performance Conclusions Reservoir simulation supports implementation of a waterflood in the Aurora Pool. Development will take place in two distinct phases. The first phase will use three horizontal wells to develop the V-200 Block and three vertical wells to develop the North of Crest area. Phase II will develop the remainder of the field. Peak production rates are expected to be 14,000 - 17,000 bopd. Upon waterflooding commencement, peak injection rates will be 20,000 - 30,000 bwpd. It is requested that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. 18/35 Aurora Pool Rules and Area I ~.on Order 5/24/2001 III. Facilities General Overview Aurora wells will be drilled from an existing IPA drill site, S-Pad, and will utilize existing IPA pad facilities and pipelines to produce Aurora reservoir fluids to Gathering Center 2 (GC2) for processing and shipment to Pump Station No.1 (PS1). Aurora fluids will be 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. The GC2 production facilities to be used include separating and processing equipment, inlet manifold and related piping, flare system, and on-site water disposal. IPA field facilities that will be used include a 24" low-pressure large diameter flowline, a 10" gas lift supply line, and a 14" water injection supply line. An 8" MI supply line from GC2 to S-Pad could be utilized for future EOR applications. The oil sales line from GC2 to PS 1 and the power distribution and generation facilities will be utilized. Exhibit III-1 is a flow diagram of the proposed Aurora Facilities at S-Pad and Exhibit 111-2 is an area map showing locations of the pad facilities that will be used for Aurora development. Drill Sites, Pads, and Roads S-Pad has been chosen for the surface location of Aurora wells to reach the expected extent of the reservoir while minimizing new gravel placement, minimizing well step out and allowing the use of existing facilities. Wells will primarily be drilled west and north of the existing IPA wells. An expansion of the existing pad size to accommodate additional wells at S-pad was completed in April, 2000. A schematic of the drill site layout is shown in Exhibit 11I-2. No new pipelines are planned for development of the Aurora reservoir. Aurora production will be routed to GC2 via the existing S-Pad low-pressure large diameter flowline. No new roads or roadwork will be required. 19/35 Aurora Pool Rules and Area In!. .on Order 5/24/2001 Pad Facilities and Operations A trunk and lateral production manifold capable of accommodating up to 20 new Aurora wells will be built as an extension to an existing S-Pad manifold system. A schematic showing the surface well tie-ins is shown in Exhibit 11I-2. Water for waterflood operations will be obtained from an extension to an existing 6" water injection supply line at S-Pad. Preliminary estimates indicate the line is sufficient to deliver water to Aurora injection wells at a rate of 28,000 bpd and a pressure of approximately 2000 - 2100 psig. Should current water injection pressures be insufficient, injection pressure can be boosted locally. An upgrade of the existing S-Pad power system should not be necessary for additional water injection booster pumps. Artificial lift gas will be obtained from the existing 10" gas lilt supply line at S-Pad. Preliminary estimates indicate that the line is sufficient to deliver gas to Aurora production wells at a rate of 30 mmscfd and a pressure of approximately 1800 psig. All well control will be performed manually by a pad operator. Exceptions to this are the automatic well safety systems and the pad emergency shutdown system that can be triggered either manually or automatically. Production allocation is addressed in Section V. Production allocation for the Aurora reservoir currently is based upon the Interim Metering Plan (approved November 15, 2000). The plan requires a minimum of two well tests per month through the S-Pad test separator for each Aurora well. Daily production is based on straight-line interpolation between valid well tests. The total volume of production from the Aurora reservoir is designated an allocation factor of 1.0. Well pad data gathering will be performed both manually and automatically. The data gathering system (SCADA) will be expanded to accommodate the Aurora wells and drill site equipment. The SCADA system will continuously monitor the flowing status, pressures, and temperature of the producing wells. These data will be under the well pad operator's supervision through his monitoring station. 20/35 Aurora Pool Rules and Area In! ,on Order 5/24/2001 Production Center No modifications to the GC2 production center will be required to process Aurora production. GC2 was built to process a nominal oil rate of 400 mbopd, gas rate of 320 mmscfd (modifications have increased this to 1,200 mmscfd) and a nominal produced water rate of 280 mbwpd. Production, including that from the Aurora Reservoir, is not expected to exceed existing GC2 capacity. 21/35 Aurora Pool Rules and Area Inj~-.~on Order 5/24/2001 IV. Well Operations Drilling and Well Design A number of wells have been drilled into the Aurora accumulation. Several exploration wells were drilled approximately 30 years ago. However, only the recently drilled S-100, S-101, S- 102, S-103, S-104, and S-105 are currently completed in the Kuparuk Formation. Many Prudhoe Bay Unit wells were logged across the Kuparuk Formation while drilling to the Ivishak Formation. However, until recently, the Kuparuk Formation was not definitively tested. In February 1999, the Aurora V-200 appraisal well was drilled off an ice pad and tested at 1900 bopd. After proving the commerciality of the Aurora Oil Pool, the V-200 well was plugged and abandoned with plans to develop the Aurora Oil Pool using existing facilities at S-Pad. More recently, the PBU Ivishak S- 24Ai well was logged and a fluid sample in the Kuparuk obtained in May 1999. The S- 24Ai well confirmed the presence of oil on the east side of the N-S dividing fault. At the present time the Aurora accumulation is being produced under Tract Operations from three wells completed in the Kuparuk Formation. Three additional wells have been drilled and will be completed shortly. Approximately fifteen (15) to nineteen (20) production and injection are forecasted for the Aurora development. Aurora development wells will be directionally drilled from S-Pad utilizing drilling procedures, well designs, and casing and cementing programs similar to those currently used in other North Slope fields. A 20-inch conductor casing will be set 80 feet below pad level and cemented to surface. Consideration will be given to driving or jetting the 20-inch conductor as an alternative setting method. A diverter system meeting AOGCC requirements will be installed on the conductor. Surface hole would be drilled no shallower than 2300 it. tvdss. This setting depth provides sufficient kick tolerance to drill the wells safely and allows the angle-build portions of high departure wells to be cased. No hydrocarbons have been encountered to this depth in previous PBU wells. Cementing and casing requirements similar to other North Slope fields have been been adopted for Aurora. 22/35 Aurora Pool Rules and Area h-~.on Order 5/24/2001 The casing head and a blowout-preventer stack will be installed onto the surface casing and tested consistent with AOGCC requirements. The production hole will be drilled below surface casing to the Kuparuk Formation, allowing sufficient rathole to facilitate logging. Production casing will be set and cemented. Production liners will be used as needed, to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells, such as high departure wells. To date, no significant H2S has been detected in the Kuparuk Formation while drilling PBU wells nor in any Aurora wells drilled to-date. However, with planned waterflood operations, there is potential of generating H2S over the life of the field. Consequently, H2S gas drilling practices will be followed, including continuous monitoring for the presence of H2S. A readily available supply of H2S scavenger, such as zinc carbonate, will be maintained to treat the entire mud system. Emergency operating and remedial protective equipment will be kept at the wellsite. All personnel on the rig will be informed of the dangers of H2S, and all rig site supervisors will be trained for operations in an H2S environment. Well Design and Completions Both horizontal and vertical wells are anticipated at Aurora. The horizontal well completions could be perforated casing, slotted liner, or a combination of both. All vertical wells will have cemented and perforated completions. Fracture stimulation may be necessary to maximize well productivity and injectivity. Tubing sizes will vary from 2-3/8 to 5-1/2 inches, depending upon the estimated production and injection rates. In general, production casing will be sized to accommodate the desired tubing size in the Aurora wells. 23/35 Aurora Pool Rules and Area In!, ~,~on Order 5/24/2001 The following table indicates casing and tubing sizes for proposed Aurora well designs. Surface Inter / Prod Casing Production Production Casing Liner Tubing Vertical 12-1/4" to 7" 9-5/8" to 4-1/2" 5-1/2" to 2-7/8" 5-1/2" to 2-3/8" Horizontal 12-1/4" to 7" 9-5/8" to 4-1/2" 5-1/2" to 2-7/8" 5-1/2" to 2-3/8" Plans are to run L-80 casing in the Aurora wells. Tubing strings will be completed with either 13-Cr 9-Cr/1Moly, or with L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/1Moly, which is compatible with both L-80 and 13-Cr. Proposed wells will be completed in a single zone (Kuparuk Formation), or multi-zone (Kuparuk and Schrader Bluff, or Kuparuk and Sag/Ivishak) utilizing a single string and multiple packers as necessary. As shown in the typical well schematics, Exhibit IV-1 for a vertical well and Exhibit IV-2 for a horizontal well, and Exhibit IV-3 for a multi-zone well, the wells have gas lift mandrels to provide flexibility for artificial lift or commingled production and injection. A sufficient number of mandrels will be run to provide flexibility for varying well production volumes, gas lift supply pressure, and water-cut. Any completions which vary from those specified in State regulations will be brought before the commission on a case by case basis. The Aurora Owners may utilize surplus [PA wells for development, provided they meet Aurora needs and contain adequate cement integrity. Initial Development The Aurora depletion plan consists of drilling six development wells under Phase I development. The S-100, S-101i and S-102 wells, an injector and two producers, are horizontal completions drilled on the west side of the N-S trending fault (V-200 Fault Block Area). Three other wells, S-103, S-104i and S-105, a multi-zone injector and two producers, are vertical completions drilled in the North of Crest area on the east side of the N-S trending fault. Injectors are being pre-produced prior to converting to permanent 24/35 5/24/2001 injection. Production from these wells will be used to evaluate the reservoir's productivity and pressure response, enabling refinement of current reservoir models and depletion plans. Current modeling suggests that the V-200 Block pre-produced injection well can be converted to injection service after six months to twelve months of primary production without jeopardizing ultimate recovery in the V-200 Block. A structure map showing the V-200 Block is shown in Exhibit I-2. In the S-100, S-101i and S-102 Phase I development wells, LWD/MWD logging was conducted after top setting the 7" intermediate casing. Plans are to set the 7" intermediate casing in the top 10-50 ft. MD (0-30 feet sstvd) of the Kuparuk Formation. The MWD will include measurement of drilling parameters such as weight on bit, rate of penetration, inclination angle, etc. LWD will include GR/Resistivity and Density and Neutron porosity throughout the build and horizontal sections. A 10-11 ppg freshwater low-solids non-dispersed mud system or equivalent will be used to drill the production hole down to the 7" casing point. The mud system parameters will be optimized to minimize mud filtrate loss before drilling the 6-1/8" horizontal section. After drilling the 6-1/8" horizontal hole, a 4-1/2" slotted or solid liner will be run, cemented and perforated as necessary Subsurface Safety Valves There is no requirement for subsurface safety valves (SSSVs) in Aurora wells under the applicable regulation, 20 AAC 25.265. Moreover, in light of developments in oil field technology and controls and experience in operating in the arctic environment, the Commission has eliminated blanket SSSV requirements from both rules governing both the Prudhoe Oil Pool and the Kuparuk River Oil Pool. See Conservation Orders 363 and 348, respectively. However, Rule 5 of Conservation Order 98A appears to require subsurface safety valves for Aurora wells. Therefore, the applicants recommend removal of the Aurora Oil Pool 25/35 Aurora Pool Rules and Area I!i-~on Ord~r~' 5/24/2001 from its scope. operations. Removing the SSSV requirement would be consistent with other PBU Existing completions are equipped with SSSV nipples, should the need arise to install subsurface storm chokes or pressure operated safety valves for future MI service. Surface Safety Valves Surface safety valves are included in the wellhead equipment. These devices can be activated by high and low pressure sensing equipment and are designed to isolate produced fluids upstream of the SSV if pressure limits are exceeded. Testing of SSVs will be in accordance with AOGCC requirements. Drilling Fluids In order to minimize skin damage from drilling and to maintain shale stability, water- based KC1 mud may be used to drill through the Kuparuk Formation at Aurora. Freshwater low solids, non-dispersed fluids will be used to drill upper sections of each well. Stimulation Methods Stimulation to enhance production or injection capability is an option for Aurora wells. There was evidence of formation damage caused by drilling and completion fluids in the V-200 well. Consequently, the need for fracture stimulation is possible. It may also be necessary to stimulate the horizontal wells, depending upon well performance. Reservoir Surveillance Program Reservoir surveillance data will be collected to monitor reservoir performance and define reservoir properties. ~ Most of the area governed originally by CO 98A was removed in 1981, when Conservation Order 173, the Kuparuk River Field, Kuparuk River Oil Pool Rules were adopted. 26/35 Aurora Pool Rules and Area Inj~.,~on Order 5/24/2001 Reservoir Pressure Measurements An updated isobar map of reservoir pressures will be maintained and reported at the common datum elevation of 6,700 ft. tvdss. An initial static reservoir pressure will be measured prior to production in at least one well for each fault block. Additionally, a minimum of two pressure surveys will be obtained annually for the Aurora accumulation, one on the east side and one on the west side of the N-S dividing fault. These will consist of stabilized static pressure measurements at bottom-hole or may be extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. It is anticipated that the operator will collect more than two pressure measurements per year during initial field development due to field complexity and fewer as the development matures. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, may be periodically run to help determine reservoir performance (i.e., production profile and injection profile evaluations). Surveillance logs will be run on multi-zone completions to assist in the allocation of flow splits as necessary. 27/35 Aurora Pool Rules and Area Inj6,.~on Order 5/2412001 V. Production Allocation Aurora production allocation will be done according to the PBU Western Satellite Production Metering Plan. Allocation will rely on performance curves to determine the daily theoretical production from each well. The GC-2 allocation factor will be applied to a{just the total Aurora production. A minimum of two well tests per month will be used to tune the performance curves, and to verify system performance. No NGLs will be allocated to Aurora. To support implementation of this procedure, several improvements to the WOA allocation system have been initiated. Conversion of all well test separators in the GC-2 area to two-phase operation with a coriolis meter on the liquid leg is expected to be completed mid-2001. The test bank meters at GC-1 and GC-2 have been upgraded as part of the leak detection system and a methodology for generating and checking performance curves for each well has been developed. Modifications to the automation system are expected to be completed mid-2001. Until the upgraded metering and allocation system for the WOA is ready for implementation, Aurora wells will use an interim metering and allocation plan based on a minimum of two well tests per month with linear interpolation and a fixed allocation factor of 1.0. We request Commission approval under 20 AAC 25.215(a) that the Aurora metering either exceeds the requirement for monthly well tests or is an acceptable alternative. 28/35 Aurora Pool Rules and Area Inje,~,ton Order 5/24/2001 VI. Area Injection Operations 29/35 Aurora Pool Rules and Area Injection Order 5/24/2001 VII. Proposed Aurora Oil Pool Rules BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that the Commission repeal Conservation Order 98A or remove the Aurora Oil Pool from its scope and adopt the following Pool Rules for the Aurora Oil Pool: Subject to the rules below and statewide requirements, production from the Aurora Oil Pool, as herein defined, may occur in a manner that will protect freshwater, prevent waste, protect correlative rights, and provide for the maximum ultimate recovery of oil and gas that is prudent. Rule 1: Field and Pool Name The field is the Prudhoe Bay Field and the pool is the Aurora Pool. The Aurora Pool is classified as an Oil Pool. Rule 2: Pool Definition The Aurora Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between log measured depths 6858.5 and 7253.5 feet in the PBU V-200 well within the following area: Umiat Meridian TllN-R12E: Sec 3:N1/2 T12N-R12E: Sec 17: S1/2; Sec 18: SE1/4; Sec 19: El/2; Sec 20: All; Sec 21: All; Sec 22: W1/2NW1/4,S1/2; Sec 23: SW1/4; Sec 25: SW1/4; Sec 26 - 28: All; Sec 29: N1/2,SE1/4; Sec 32: El/2; Sec 33- 35: All; Sec 36: N1/2,SW1/4 Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer to 500 feet to an external boundary where ownership changes. Rule 4: Automatic Shut-In Equipment (a) All wells capable of unassisted flow of hydrocarbons will be equipped with a fail-safe automatic surface safety valve. (b) Injection wells will be equipped with a hil-safe automatic surhce safety valve. (c) Surface safety valves will be tested in accordance with Commission requirements. Rule 5: Common Production Facilities and Surface Commingling (a) The PBU Western Satellite Metering Plan satisfies the well testing requirements of 20 AAC 25.230 and 20 AAC 25.275. 30/35 Aurora Pool Rules and Area Inj~,lon Order 5/24/2001 (b) Each producing Aurora well will be tested and production will be allocated in accordance with the Prudhoe Bay Unit Western Satellite Metering Plan. (c) Allocated production for Aurora will be adjusted in conjunction with the GC-2 allocation factors. (d) Until the Prudhoe Bay Unit Western Satellite Metering Plan is implemented, the operator shall submit monthly reports containing daily allocation and well test data for agency surveillance and evaluation. During this period, each producing Aurora well will be tested a minimum of two times per month with production allocated by straight-line interpolation between well tests. The Aurora allocation factor will be 1.0 Rule 6: Reservoir Pressure Monitoring (a) A minimum of two pressure surveys will be taken annually for the Aurora Pool. (b) The reservoir pressure datum will be 6700 feet true vertical depth subsea. (c) Pressure surveys may consist of stabilized static pressure measurements at bottom- hole or extrapolated from surface, pressure fall-off, pressure build-up, multi-rate tests, drill stem tests, and open-hole formation tests. (d) Data and results from pressure surveys shall be reported annually. (e) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (d) of this rule. Rule 7: Gas-Oil Ratio Exemption Wells producing from the Aurora Oil Pool are exempt from the gas-oil ratio limit set forth in 20 AAC 25.240(b). Rule 8: Pressure Maintenance Project Water injection for pressure maintenance will commence before reservoir pressure drops below 2500 psi at the datum or within eighteen months of initial production. Rule 9: Reservoir Surveillance Report A surveillance report will be required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: 1. Summary of produced and injected fluids. 2. Summary of reservoir pressure analyses within the pool. 3. Results of well allocation and test evaluation for Rule 7 and any other special monitoring. 4. Future development plan. The report will be submitted to the state by April l"t each year. Rule 10: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does 31/35 Aurora Pool Rules and Area Injectmn Order 5/24/2001 not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 32/35 n!i~ ion Aurora Pool Rules and Area I , Order 5/24/2001 VIII. Area Injection Application BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Aurora Pool and consider the following rules to govern such activity: Affected Area: TllN-R12E: Sec 3:N1/2 T12N-R12E: Sec 17: S1/2; Sec 18: SE1/4; Sec 19: El/2; Sec 20: All; Sec 21: All; Sec 22: W1/2NW1/4,S1/2; Sec 23: SW1/4; Sec 25: SW1/4; Sec 26- 28: All; Sec 29: N1/2,SE1/4; Sec 32: El/2; Sec 33- 35: All; Sec 36: N1/2,SW1/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids appropriate for enhanced oil recovery may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to, and correlate with, the interval between the measured depths of 6858 and 7252 feet in the PBU V-200 well. Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well tbr 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. Rule 3: Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4: Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 6 below. Rule 5: Demonstration of Tubing/Casing Annulus Mechanical Integrity 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. A test surface pressure of 1500 psi or 0.25 psi/ft, multiplied 33/35 Aurora Pool Rules and Area In jcl.on Order 5/24/2001 by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 70% of the casing's minimum yield strength will be used. The test pressure must show a stabilizing trend and must not decline more than 10% in a thirty-minute period. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever operating pressure observations, injection rates, or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval to continue injection and submit a plan of corrective action on Form 10-403 for Commission approval. Rule 7: Plugging and Abandonment of Injection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8: Notification The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State of Federal agency remain the Operators' responsibility. Rule 9: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above 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 an increased risk of fluid movement into an underground source of drinking water (USDW). 34/35 Aurora Pool Rules and Area In jLa.on Order 5/24/2001 IX. List of Exhibits I-1 Aurora Pool Location Map I-2 Top Structure Map I-3 Aurora Participating Area (APA) I-4 Type Log for Aurora Pool 1-5 Aurora Areas I-6 Structural Cross Section I-7 Dip Seismic Cross Section I-8 Strike Seismic Cross Section I-9 Fluid Contacts 1-10 Net C4/C3B Sand Map 1-11 Net C3A/C1 Sand Map I- 12 Net A Sand Map I- 13 Net Hydrocarbon Pore Foot Map II-1 Model Layering and Properties II-2 Aurora Fluid Properties I1-3 PVT Properties I1-4 Production and Recovery Profiles for Primary Depletion II-5 Production and Recovery Profiles for Water Injection III- 1 Ill-2 IV-1 IV-2 IV-3 Aurora Well Tie-ins - Northern S-Pad Aurora Facility Location Typical Vertical Completion Typical Horizontal Completion Schrader-Kuparuk Injection Well 35/35 Exhibit I-1: Aurora Pool Location Map SANDPIPER UNIT _ MH,,bI~POI~ UNff ~ ~ ,.,,,,~,,.-,,~,,:.,,,,,- J'--' Th ;~""' .~'"~C~.-.._ "-' .O.T.m'~u..' ' "~ . I ' ,,~~' -'~'L, .-~'~ ' : · -'"~ "--~ ! I 'C ~ 2, ' ~[ ~.'\ ~ '"..,., L . ~ ! i , ~ ,/ / ~_-.~' -.,.,x._ , ,, ._.r ". .1' ? .___:'" L....J' -L.' . ! "~~-" i-. - -I KUPARUK RIVER UNIT ! PRUDHOE BAY UNIT Exhibit I-2' Top Structure Map EXHIBIT I-3 AURORA PARTICIPATING AREA (APA) ADL,28254 ADL 28253 ~ ADLt 385193 , I ' , / I ADL 202551 A~ 28256 ADLt47448 19,] 20 I 2 22 23 I Expansion I Exp I ' I ~ ~0 29 I ~ 28 27 26 25 I I I I I ~ I I 1 I APA ADL~28259 I ADL 28258 ADL 28257 I I I ..................................... !~ ,=x"ans=on_. _Expansion T 12N-R 12E I Area2 ~ Areal ~ ~ ~ 34 35 36 , I '~ I T11N-R12E : 4 3 2 1 t ....... Exhibit I-5' Aurora Areas Beechey Block North of Crest Block Eastern Block Exhibit I-6: Structural Cross Section A Exhibit I-7: Dip Seismic Section Beechey F'~ #~! V*200 S-03 S~6 St4 Kupa~uk Exhibit I-8' Strike Seismic Section S,~ N, K~.lp 2(¥ Soha~ade~ Blu~ Kuparuk Exhibit I-9: Fluid Contacts Contact Beechey Block V-200 Block Crestal Block GOC 6678' tvdss Per 6631' tvdss (Beechey Pt St #1) Beechey Block (S-16) WOC 6835' tvdss 6824' tvdss 6812' tvdss (Beechey Pt St #2) (V-200) (N Kup 26-12-12) Exhibit I~ 10: Net C4/C3B Sand Map Exhibit 1-11' Net C3A/C1 Sand Map RU~ORR ~IELO Exhibit 1-12: Net A Sand Map Exhibit I-13: Net Hydrocarbon Pore Foot Map I I I -I-- - 4 I I I PBU Bo~ PA Boundo~ RURORR FIELO TOTRL KUPRRUK Exhibit II-1: Model Layering and Properties Average Properties by Simulation Layer Layer Zone Porosity lgermeability Gross Net Pay Initial (%) (md) Thickness (ft) Water Sat fit) (%) *3 *3 *1 *2 *2 1 C4B 21 59 13 4 45 2 C4A 25 158 24 22 30 3 C3B 19 12 21 18 36 4 C1 19 42 15 7 60 5 A5 16 29 20 9 66 * 1 Based upon stratigraphic formation marker picks. *2 Based upon Aurora Log Model. *3 Based on routine core data. Exhibit II-2: Aurora Fluid Properties Initial Reservoir Pressure at 6700' tvdss Bubble Point Pressure Reservoir Temperature Oil Gravity Reservoir Oil Viscosity Reservoir Water Viscosity Reservoir Gas Viscosity Solution Gas/Oil Ratio (Rs) Oil Formation Volume Factor (Bo) Water Formation Volume Factor (Bw) Gas Formation Volume Factor (Bg) 3433 psia 3433 psia 150° F 25°- 30° AP1 0.722 cp 0.45 cp 0.022 cp 717 SCF/STB 1.345 RBL/STB 1.03 RBL/STB 0.843 RBL/MSCF Exhibit II-3: PVT Properties · .Pressu.r.e. ................. ~ ......................... B~! ....................... Oi! ...................... ~s ................ So.!,ution cp cp scf/STB 3464 1.345 0.722 717 ~ i'~)'(~ ............... 'i"13'~ ............. ~)18~ .............. 0'17'~4' ......... 0'i02~ '6~ 2750 1.289 0.945 0.789 0.020 575 2400 1.262 1.083 0.858 0.019 508 2050 1.236 1.275 0,958 0.017 441 1700 1.210 1.554 1.100 0,016 375 1350 1.185 1.987 1,280 0.015 309 1000 1.159 2.732 1,530 0,014 244 650 1.133 4.283 1.880 0,013 177 300 1.102 9.340 2.440 0,012 105 124 1.081 21.615 2,950 0,011 61 0 1,041 4,520 0 Exhibit :{1-4: Producti(m and Recovery Profiles for Primary Dep~etioa oil Prl~uctioa water Production ] 0.0(}0 r -- ------~ 2,o0o I Year Year 30,00{} Gas Production ~ 2(tO00 ~ 15,000 ~ ] 0,(×)0 © 5 ,(X)O 2000 2005 2010 2015 2020 2025 2030 Ye~tr Oil Recovery 14 12 5 ~o 8 6 ~ 4 2 0 //------- 2(X)O 2(X)5 2010 2015 2020 2025 Year Exhibit II-5: Production and Recovery Profiles for Water Injection 12.000 I0,000 $,000 64)00 4,0oo 2,000 Oil Production ~ibd -~-- sclTstb 1,500 900 60O 300 2005 2010 2015 2020 2025 2030 4,000 3,500 1,(×)0 500 Water Production 2(X)(} 2(X)5 2010 2015 2020 2025 2030 Year [ Year i 25 20.(X)0 I0.000 5.000 Gas Production ()il Recovery 40 ~ 2000 2(X)5 20t0 2(`)15 2020 2025 2030 [ 2000 2005 2010 2(.)15 2020 2025 Year i Year Exhibit III- 1 Aurora Well Tie-ins - Northern S-Pad To/From Module 57 $- 4 Line (lfnece~ssary) To/From ModuLe 93 Polaris Well Aurora Well [PA Well Poteutlal Well Exhibit III-2: Aurora Facility Location Production (#) Test (#) ; Gas Lift (#) Water (#) MI (#) Future Equipment (#) Aurora Well Existing Polaris Well IPA Well # - Surface Satellite Equipment l~tjectio~ Water Line Tie-in (IPA injection well) [/gTie-ins Exhibit IV-1' Typical Vertical Completion nipple 2000' X nipple (/t3=3.81 Y') XN nipple w/NoGo Conductor Casing ~ 20" casing Surface Casing 4355'MI) 3285'ssTVD < 12-1/4 hole %5/8 or 7-5/8 casing Tubing 4 1/2 or 3-1/2" ct-g0 Tbg 3 GLM's Prodt~ction Pkr. 6600' ssTVD Kuparuk C sand perfs Kuparuk A sand peritx Pr{aluction Casing 6900' sstvd < 9C/g' hole 7 or 5~t/2 ' casing Exhibit IV-2: Typical Horizontal Completion X-I~ippk' 2000' 55~' ~ ge t X t~ipple (ID=3 gl 3") XN nippk' w/NcKR~ Top Kt/par~lk 6673' sstvd Intermediate Casing 10400' MD 6678' sslvd 9 7/8 hole 7 or 5 lA?" casing Conductor Cash~g ~ 20" casing Snd~ace Casing 4355' MD 3285'ssTVD 13 i12 hole 3/4 or 9 5A5' casing Tubing ~!/2 oI .'~ 1/2 ~' CI 80 Tbg ¢ GLM's 10,300' MD 6618' ssTVD Prf~uction Liner 11852' MD 6700 67i2' sstvd 6 3/,~ hole T..~RF_E -~ ,, 4-1/8" 5M WFI LHF__AD-= FMC 11" A CTUA TO R= KB. ELEV = 64.5 '~'1~'."~"~'~'''-' .............................. 35.9 K;OP = 300' ~'";~'~'~i~'":' ............... ~'~;'"~'";~'~6'6 i%i~'fi~'-~'b'-" ............ 87~'d'~'§' 9-5/8" 40# L-80 BTCI I 3736' Minimum ID = 3.725" @ XN nipple Exhibit IV-3: Schrader-Kup~:' '~ Injection Well S-104i SA FETY NOTES: ACTUAL DEPTHS WILL BE PROVIDED BEFORE COMPLETION 2403' ] I X-Nipple, 3.813" ID 1 STA MD TVD DEV TYPE MAN LATCH GLM5 4839 3495 54 KBG-2-T/L BK GLM4 6731 4883 31 KBG-2-T/L BK GLM3 6920 5046 29 KBG-2-T/L BK SLSV 7035 5147 29 Baker CMU BK IGLM2 7117 5218 30 KBG-2-T/L BK SLSV 7175 5268 30 Baker CMU BK GLM1 7266 5347 30 KBG-2-T/L BK SLSV 7333 5406 30 Baker CMU BK ,6842' 1 --~6853' I ~7061' 4-1/2"X, 3.813" ID I I Baker S-3' 7" x 4'5" I Baker SABL-3 I ~,7201' I Baker SABL-3 I I4'1/2'' 12'6#/ft L'80NSCT { I PERFORATION SUMMARY REF LOG: Ref Platform Express GR/Res 1/27/2001 ANGLEAT TOP PERF: I 29 I Note: Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 4.63 6 6920-6980 Open 2/4/2001 " 6 7018-7050 Open 2/4/2001 " 6 7070-7094 Open 2/4/2001 " 6 7114-7124 Open 2/4/2001 " 6 7162-7182 Open 2/4/2001 " 6 7216-7266 Open 2/4/2001 " 6 7280-7302 Open 2/4/2001 " 6 7325-7346 Open 2/4/2001 --~,8679' 87O3' 8724' .8736' ] [ Baker SABL-3 { I [ 4-1/2"X, 3.813" ID I 1 I 4-1/2" XN, 3.725" ID I I I w' oI I I . 00' I 7" 26# L-80 m-BTC 1 I 9,86' I I DATE REV BY COMMENTS 01/08/01 P. Smith Original Proposed Completion 02/09/01 P. Smith As-Completed PRUDHOE BAY UNIT / AURORA FIELD WELL: S-104i PERMIT No: 200-196 APl No: 50-029-22988-00 Sec. 35, T12N, R12E, 4494' FEL, 633' FNL BP Exploration (Alas ka) #1 NAME - AFFILIATION ALASKA OIL AND GAS CONSERVATION COMMISSION Date: ~' Z. ~/'L~ [ Time /L~ 'LPO MEETING _ Subiect AY ,~o r-a-- ~ t~ ~ ~' ~ ~ ZZ~ ~ TELEPHONE (PLEASE PRINT)
