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Home My WebLink AboutAIO 022 ) ) Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. A'"!. n ð d ~ Order File Identifier D Other:: I Date: 1/:J.C6 OS 151 vvP I 1111111111111111111 Date: ~Jð o..ç 151 Vij.~ '/,1;,- X 30 = .~.~ D + '6 = .TOTA~ PAGES 33ð' . . (Count d-;es not i Ielude cover sheet) MD" Date: I 6i7! {2Ç" /5/ { . ",- 1111111111111111111 Page Count from Scanned File::3 3 c¡ (Count does include C07 sheet) Page Count Matches Number in Scanning Preparation: V YES . 1 Helen ~ Date: I, ~ a.r If NO in stage 1, page(s) discrepancies were found: YES NO Organizing (done) 1I1I11I111111111111 0 Two-sided RES CAN DIGITAL DATA ~olor Items: 0 Diskettes, No. D Greyscale Items: 0 Other, NolType: Woor Quality Originals: ßfa.d<. 4 ~ fLtc..~) 0 Other: NOTES: BY: Helen~ Project Proofing BY: Helen C Maria) Scanning Preparation BY: Helen -~ \ Production Scanning Stage 1 BY: Stage 1 BY: Helen Maria Scanning is complete at this point unless rescanning is required. ReScanned BY: Helen Maria Comments about this file: ~escan Needed 1111111111111111111 OVERSIZED (Scannable) 0 Maps: 0 Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) 0 Logs of various kinds: NO 151 ~fJ Date: /5/ I I 1111111111111 Date: /5/ Quality Checked 1111111111111111111 12/1/2004 Orders File Cover Page.doc 1. May 24, 2001 2. May 24,2001 3. June 15, 2001 4. June 21, 2001 5. 5a July 24, 2001 6. July 23,2001 7. July 24,2001 8. July31,2001 9. August 15,2001 10. August 17,2001 11. Various e-mails 12. March 7, 2003 13. January 9, 2005 ) ) AIO ORDER NO. 22 AURORA OIL POOL Sign In Sheet for Meeting between AOGCC/BP Aurora Pool Rules and AIO, Confidential Exhibit II-6 a. 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 a. AIO Confidential Supplementl, Exhibit VI-1 through VI-9 in ConfRoom Transcript (Confidential portion in Conf Room) Second Supplemental Data - Aurora Pool Rules and a. AIO Oversized Display Exhibit VI-17, VI-17A, VI-17B, Map AI, A2, A3 HCPF, a. Map B7L, B7L, B7U, CP and Map 101113 in b. Confidential Room Letter from Phillips to AOGCC Colored Exhibits submitted by BPXA E-mail from Marc Kovak AIO 22, effective date 9/7/01. Revised AIO 22 done 9/17/02. ) i <!(I¿¿ {.( ¿ c-( 5/8'/('3 -'iI-C" )( 3/.:::: 3f; f?ý STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska ) Prudhoe Bay Field ) Aurora Oil Pool ) ) Order Granting Rehearing of Area ) Injection Order No. 22A ) and Decision upon Rehearing ) On April 3, 2003, the Commission issued Area bijection Order No. 22A, denying the application of BP Exploration (Alaska) Inc. ("BPXA") for authorization of underground injection of miscible injectant for enhanced oil recovery in the Aurora Oil Pool, Prudhoe Bay Field. On April 28, 2003, BPXA applied for rehearing under AS 31.05.080(a). The Commission has considered BPXA's application for rehearing and the written materials submitted in support of that application and has determined that they are sufficient to justify rehearing of Area Injection Order No. 22A. The Commission has further determined that the documents submitted are sufficient to rule on the merits of the application without need for a further' oral hearing. The Commission's ruling on the merits is contained in Area Injection Order No. 22B, which is incorporated herein by reference. IT IS SO ORDERED. DONE at Anchorage, Alaska and dated May 6,2003. GA~?J ~ Alaska Oil and Gas ~nservation Commission ~ £4'~ Randy Ruedrich, Commissioner ø~~ation Comnñssion Daniel T. SeañíOunt, Jr., Commissioner Alaska Oil and Gas Conservation Commission .) - q ¡.{tulLe) ,./Ýo~ C¡jx,3í7.;; 35./6 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 allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska ) Area Inj ection Order No. 22 ) Prudhoe Bay Field ) Aurora Oil Pool ) ) ) Corrected date: September 17, 2002 ) Effective date: September 7, 2001 ERRATA NOTICE After the issuance of Area Injection Order 22, the Alaska Oil and Gas Conservation Commission ("Commission") determined there was an error in Rule 2 of the Order. Area Injection Order 22 is corrected as follows: Rule 2: Change "6700' tvdss" to "surface". DONE at Anchorage, Alaska and dated September 17, 2002. ~t~ ~Jul,--k.PClA Cammy Oeq~Jli Taylor, Ch~;'"' .- Alaska Oil añd Gas Conservation Commission ø~ Daniel T. Seá'mount, Jr., Commissioner Alaska Oil and Gas Conservation Commission ./.. ~ø PlL ~ ,ll'v~~\ II ~~ .¡~~ ~~ I f ;~% -', VI",'~I~ !':.";L,.;¿--- ~h.... ..... ...,.-:;",;¿'L~-." -"'~. -...;",. ~ ;.,-:/7-':'1/. i\. ;¡~J~.) f: ~~~ ~ lo.''"~ I' \.It'íf:l..k '\ I .. v [of j. ,,»~¿":~"'."jI. /:i~ \t .;~!'~;~~~ , ,O'Þ': (,(\t~I~~, J" ~ , ¡:,<;!o:;~J~~!~. ' ) ~ ',:.::;:<~¥~~~~f~o, ¡FAg} ,:;.<~:.i ~'~~o~~i-2~r;' ~:;?/ ,:! ~...:.' ,--.~,;~:- ~~~~ ":~"~'~".?.:2~ , ) ) ,\ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West ih Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska ) Area Injection Order No. 22 ) Prudhoe Bay Field ) Aurora Oil Pool ) ) ) September 7, 2001 ) (Corrected September 17,2002) IT APPEARING THAT: 1. 2. 3. 4. 5. 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") authorizing the injection of fluids for enhanced oil recovery in the Aurora Oil Pool ("AOP") within the Aurora Participating Area and defined expansion areas ("AP A") in the Prudhoe Bay Unit. 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. ih Avenue, Suite 100, Anchorage, Alaska 99501 on July 24, 2001. Concurrently, the Commission heard testimony concerning proposed pool rules for the AOP. 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 was requested by the Commission at the hearing and has been provided to the Commission. This supplemental information was submitted by letter from BPXA dated July 31, 2001. FINDINGS: 1. Commission regulation 20 AAC 25.402 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. ') Area Inj ection Order No ¿ September 7, 2001 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. Page 2 Concurrent to this order, the Commission revised pool rules governing the AOP (Kuparuk River Oil Pool) by Conservation Order 457. The APA is located in portions of Township l2N-R12E, and T1lN-R12E, Umiat Meridian, on Alaska State Leases ADL-28255, ADL-28256, ADL-28257, ADL- 28258, ADL-28259, and ADL 28261. The APA is located within the current boundaries of the Prudhoe Bay Unit ("PBU"), North Slope, Alaska. BPXA is the operator of the AP A. BPXA, Phillips Petroleum, Co., ExxonMobil Corporation, and Forest Oil are working interest owners ("WIOs") in the AP A. The State of Alaska is the surface owner. The reservoir interval for proposed injection is the Kuparuk River Formation. The AOP is defined as an accumulation of oil that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12. 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. Original oil in place ("OOIP") is estimated to be 110 to 146 MMSTB. Waterflood is part of BPXA current development plans. Additional recovery by waterflood over primary recovery in the AOP is estimated between 15-25% of the original oil in place. Production rate peak for the proposed development plan with water injection is estimated at 14,000-17,000 bopd with a maximum water injection rate of 20,000- 30,000 bwpd. 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. Produced water from PBU Gathering Center 2 will be injected into the AOP. Water injection operations at the AOP are expected to be conducted at pressures above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Based upon S-10 1 leakoff test, the fracture gradient within the Kuparuk formation of the AOP is approximately. 73 psi/ft The Kuparuk River Formation at the AOP 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/ft. Underlying the Kuparuk River Formation is the MiluveachlKingak shale sequence. Leakoff tests in the Kingak shale show a fracture gradient of approximately .85 psi/ft. ) Area Injection Order No::' ) September 7, 2001 16. 17. 18. 19. 20. 21. Page 3 Expected average wellhead injection pressure is 1800 psi with present facilities. A surface booster pump may be installed at a later date to increase wellhead pressure and ensure injection rates. BPXA plans to keep injection pressures below 5500 psi at 6700' TVD, under the fracture gradient of the confining intervals. This roughly corresponds to a maximum surface pressure of 2600 psi. BPXA is concurrently requesting conversion of S-l 0 1 to water injection for support of current producers (S-100 and S-102). The development of the proposed AP A 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. There are no freshwater strata in the area of the proposed injection. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An Area Injection Order is appropriate for the project area in accordance with 20 AAC 25.460. 3. There are no freshwater strata in the AOP area. 4. The proposed injection operations will be conducted in permeable strata, and may involve injection above the parting pressure of the Kuparuk Formation in the AOP. The injection pressures will be maintained below the fracture pressures of the confining intervals. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 6. 7. 8. Implementation of an enhanced recovery operation involving injection of produced water from the Prudhoe Bay Unit will preserve reservoir pressure/energy and enhance ultimate recovery. The proposed AP A water injection project will result in approximately twenty (20) percent increased recovery over primary production alone. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project Area Injection Order No 2,. ') September 7, 2001 ') Page 4 or disclose possible abnonnalities. 9. An Area Injection Order enabling enhanced oil recovery activity will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED THAT: 1. This corrected AIO supersedes AIO 22 dated September 7,2001. 2. The underground injection of produced water pursuant to the project described in BPXA's application is pennitted in the following area, subject to the conditions, limitations, and requirements established in the rules set out below: Umiat Meridian Township Range TllN R12E T12N R12E Sections N ~ Sec. 3 S ~ Sec 17; SE ~ Sec 18; E ~ Sec 19; All Sec 20; All Sec 21;W 1/2NW 1/4,S ~ Sec 22; SW ~ Sec 23; SW ~ Sec 25; All Sec 26; All Sec 27; All Sec 28; N ~, Se ~ Sec 29; E ~ Sec 32; All Sec 33; All Sec 34; All Sec 35; N ~, SW ~ Sec 36 Rule 1 Authorized Iniection Strata for Enhanced Recovery Injection is pennitted into the accumulation of hydrocarbons that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well. Rule 2 In,iection Pressures The injection pressure shall be limited to 2600 psi at surface, so as to ensure fractures do not propagate into the confining shale intervals. Rule 3 Fluid In.i ection Wells The underground injection of fluids must be through a well pennitted for drilling as a service well for injection in confonnance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in confonnance with 20 AAC 25.280. Rule 4 Monitorin2 the Tubin2-Casine Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confinn continued mechanical integrity. Rule 5 Demonstration of Tubine-Casine Annulus Mechanical Inteerity 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. Area Injection Order No ~,) September 7, 2001 ') Page 5 Rule 6 Notification of Improper Class II Iniection The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 7 Other conditions a. It is a condition of this authorization that the operator comply with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 8 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 in an increased risk of fluid movement into a USDW. Corrected at Anchorage, Alaska on September 17, 2002. Effective September 7, 2001. (' .., rtI,,- [L ,J ,,'- ~ bt \Jl;'VV\'~v>f..c}tLJ' , 'L--' Cammy ~hsli Taylor, C. ir ~, ' aska OJ!. an~s Conservation Commission XJ ~~7 Daniel T. Seamount, Jr., Commissioner Alaska Oil and Gas Conservation Commission ) John Katz State of Alaska Alaska Governor's Office 444 North Capitol S1., NW, Ste 336 Washington, DC 20001 ) Daniel Donkel 2121 North Bayshore Drive, Ste 1219 Miami, FL 33137 SD Dept of Env & Natural Resources Oil and Gas Program 2050 West Main, Ste 1 Rapid City, SD 57702 Alfred James 107 North Market Street, Ste 1000 Wichita, KS 67202-1822 Christine Hansen Interstate Oil & Gas Compact Comm Excutive Director PO Box 53127 Oklahoma City, OK 73152 Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Conoco Inc. PO Box 1267 Ponca City, OK 74602-1267 Mir Yousufuddin US Department of Energy Energy Information Administration 1999 Bryan Street, Ste 1110 Dallas, TX 75201-6801 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 Gregg Nady Shell E&P Company Onshore Exploration & Development PO Box 576 Houston, TX 77001-0576 Michael Nelson Purvin Gertz, Inc. Library 600 Travis, Ste 2150 Houston, TX 77002 Paul Walker Chevron 1301 McKinney, Rm 1750 Houston, TX 77010 G. Scott Pfoff Aurora Gas, LLC 10333 Richmond Ave, Ste 710 Houston, TX 77042 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 G. Havran Gaffney, Cline & Associations Library 1360 Post Oak Blvd., Ste 2500 Houston, TX 77056 William Holton, Jr. Marathon Oil Company Law Department 5555 San Fecipe S1. Houston, TX 77056-2799 T.E. Alford ExxonMobilExploration Company PO Box 4778 Houston, TX 77210-4778 Texico Exploration & Production PO Box 36366 Houston, TX 77236 Corry Woolington ChevronT exaco Land-Alaska PO Box 36366 Houston, TX 77236 W. Allen Huckabay Phillips Petroleum Company Exploration Department PO Box 1967 Houston, TX 77251 Chevron USA Alaska Division PO Box 1635 Houston, TX 77251 Donna Williams World Oil Statistics Editor PO Box 2608 Houston, TX 77252 Chevron Chemical Company Library PO Box 2100 Houston, TX 77252-9987 Shawn Sutherland Unocal Revenue Accounting 14141 Southwest Freeway Sugar Land, TX 77478 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 James White Intrepid Prod. Co./Alaskan Crude 4614 Bohill SanAntonio, TX 78217 Doug Schultze XTO Energy Inc. 3000 North Garfield, Ste 175 Midland, TX 79705 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 ) John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 ) Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 John F. Bergquist Babson and Sheppard PO Box 8279 Long Beach, CA 90808-0279 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Thor Cutler OW-137 US EPA egion 10 1200 Sixth Ave. Seattle, WA 98101 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Susan Hill State of Alaska, ADEC EH 555 Cordova Street Anchorage, AK 99501 Tim Ryherd State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Williams VanDyke State of Alaska Department of Natural Resources 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Cammy Taylor 1333 West 11th Ave. Anchorage, AK 99501 Ed Jones Aurora Gas, LLC Vice President 1029 West 3rd Ave., Ste 220 Anchorage, AK 99501 Richard Mount State of Alaska Department of Revenue 500 West 7th Ave., Ste 500 Anchorage, AK 99501 Julie Houle State of Alaskan DNR Div of Oil & Gas, Resource Eva!. 550 West 7th Ave., Ste 800 Anchorage, AK 99501 Robert Mintz State of Alaska Department of Law 1031 West 4th Ave., Ste 200 Anchorage, AK 99501 Duane Vaagen Fairweather 715 L Street, Ste 7 Anchorage, AK 99501 Jim Arlington Forest Oil 310 K Street, Ste 700 Anchorage, AK 99501 Trustees for Alaska 1026 West 4th Ave., Ste 201 Anchorage, AK 99501-1980 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 John Harris NI Energy Development Tubular 3301 C Street, Ste 208 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Mark Dalton HDR Alaska 2525 C Street, Ste 305 Anchorage, AK 99503 Mark Hanley Anadarko 3201 C Street, Ste 603 Anchorage, AK 99503 Judy Brady Alaska Oil & Gas Associates 121 West Fireweed Lane, Ste 207 Anchorage, AK 99503-2035 Arlen Ehm 2420 Foxhall Dr. Anchorage, AK 99504-3342 Greg Noble Bureau of Land Management Energy and Minerals 6881 Abbott Loop Rd Anchorage, AK 99507 Rose Ragsdale Rose Ragsdale & Associates 3320 E. 41st Ave Anchorage, AK 99508 Jeff Walker US Minerals Management Service Regional Supervisor 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 ) Paul L. Craig Trading Bay Energy Corp 5432 East Northern Lights, Ste 610 Anchorage, AK 99508 ) Jim Scherr US Minerals Management Service Resource Evaluation 949 East 36th Ave., Ste 308 Anchorage, AK 99508 Chuck O'Donnell Veco Alaska,lnc. 949 East 36th Ave., Ste 500 Anchorage, AK 99508 Richard Prentki US Minerals Management Service 949 East 36th Ave., 3rd Floor Anchorage, AK 99508 Thomas R. Marshall, Jr. 1569 Birchwood Street Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jim Ruud Phillips Alaska, Inc. Land Department PO Box 100360 Anchorage, AK 99510 Kristen Nelson IHS Energy PO Box 102278 Anchorage, AK 99510-2278 Perry Markley Alyeska Pipeline Service Company Oil Movements Department 1835 So. Bragaw - MS 575 Anchorage, AK 99515 Jordan Jacobsen Alyeska Pipeline Service Company Law Department 1835 So. Bragaw Anchorage, AK 99515 Robert Britch, PE Northern Consulting Group 2454 Telequana Dr. Anchorage, AK 99517 David Cusato 600 West 76th Ave., #508 Anchorage, AK 99518 Jeanne Dickey BP Exploration (Alaska), Inc. Legal Department PO Box 196612 Anchorage, AK 99518 Jack Laasch Natchiq Vice President Government Affairs 6700 Arctic Spur Road Anchorage, AK 99518 Tesoro Alaska Company PO Box 196272 Anchorage, AK 99519 J. Brock Riddle Marathon Oil Company Land Department PO Box 196168 Anchorage, AK 99519-6168 Kevin Tabler Unocal PO Box 196247 Anchorage, AK 99519-6247 Sue Miller BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 BP Exploration (Alaska), Inc. Land Manager PO Box 196612 Anchorage, AK 99519-6612 Dudley Platt D.A. Platt & Associates 9852 Little Diomede Cr. Eagle River, AK 99577 Bob Shavelson Cook Inlet Keeper PO Box 3269 Homer, AK 99603 Shannon Donnelly Phillips Alaska, Inc. HEST-Enviromental PO Box 66 Kenai, AK 99611 Kenai Peninsula Borough Economic Development Distr PO Box 3029 Kenai, AK 99611 James Gibbs PO Box 1597 Soldotna, AK 99669 Claire Caldes US Fish & Wildlife Service Kenai Refuge PO Box 2139 Soldotna, AK 99669 Penny Vadla Box 467 Ninilchik, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 John T anigawa Evergreen Well Service Company PO Box 871845 Wasilla, AK 99687 Richard Wagner PO Box 60868 Fairbanks, AK 99706 ') Cliff Burglin PO Box 131 Fairbanks, AK 99707 Harry Bader State of Alaska Department of Natural Resources 3700 Airport Way Fairbanks, AK 99709 ) Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 Senator Loren Leman State Capitol Rm 113 Juneau, AK 99801-1182 Re: [Fwd: Aurora injection Pressure] ) ) Subject: Re: [Fwd: Aurora injection Pressure] Date: Sat, 14 Sep 2002 11 :36:24 -0800 From: Cammy Oechsli Taylor <Cammy - Taylor@admin.state.ak.us> Organization: DOA-AOGCC To: Jody J Colombie <jody - colombie@admin.state.ak.us> CC: Jane Williamson <Jane- Williamson@admin.state.ak.us>, Dan Seamount <dan _seamount@admin.state.ak.us> Jody, I e-mailed you a draft of the Errata Notice, and left hard copies of the AlO with corrections & additions in pink. Jane's e-mail should also go in the AlO file to explain the change. Thanks, Cammy Jane Williamson wrote: > > Carruny, > The Aurora AI022 had an error per my note below. I have attached > a copy > of a corrected version. I am not sure of our process on this, but > it > was definitely in error. I'll corne by Monday after PE school and > see if > I need to do anything on this. > Jane > > ------------------------------------------------------------ > > Subject: Re: Aurora injection Pressure > Date: Fri, 13 Sep 2002 13:39:18 -0800 > From: Jack Hartz <jack_hartz@admin.state.ak.us> > To: Jane Williamson <Jane Williamson@admin.state.ak.us> > References: <3D813F42.19D022D5@admin.state.ak.us> > > I think all that has to be done is issue a correction to the > Order. The original date is noted and the date the correction is > also noted. That is unless there are newer procedures for issuing > corrections. > > jack > > Jane Williamson wrote: > > > Jim, > > Thank you for calling concerning the AI022. You are correct, > > there is a typo in Rule 2. It should read "Injection pressure > > shall be limited to 2600 psi at surface" not bottom-hole. I > > will get an administrative order out to correct this and you > > will hopefully have it next week. > > > > Thanks, > > Jane > > > Jack Hartz <jack_hartz@admin.state.ak.us> Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission > > > > Jack Hartz Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission <jack_hartz@admin.state.ak.us> > > 10f2 9/17/20028:47 AM Re: [Fwd: ~urora injection Pressure] 20f2 > > 333 West 7th Anchorage AK 99501 Additional Las t Name Firs t Name Version > > > > > > > > ) ) Avenue Suite 100 .. .;'¡;;¡;;^;;;;"'~"";-""'I""''''''~;';;;~:¡:;;;'':'''. Fax: 907-276-7542 Work: 907-793-1232 ------------------------------------------------------------ Information: Hartz Jack 2.1 > > AI022Corrected021602.doc Name: AI022Corrected021602.doc Type: WINWORD File (application/msword) Encoding: base64 > > - - ---.~-- -- . - - - -.. --- --- ---- Cammy Oechsli Taylor <cammy_taylor(â.ladmin.state.ak.us> Commissioner Alaska Oil and Gas Conservation Commisison Department of Administration 9/17/2002 8:47AM ) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West ih Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BPXA EXPLORATION (ALASKA) INC. for an order allowing underground injection of fluids for enhanced oil recovery in Aurora Oil Pool, Prudhoe Bay Field, North Slope, Alaska ) Area Injection Order No. 22 ) Prudhoe Bay Field ) Aurora Oil Pool ) ) ) ) September 7, 2001 IT APPEARING THAT: 1. 2. 3. 4. 5. 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") authorizing the injection of fluids for enhanced oil recovery in the Aurora Oil Pool ("AOP") within the Aurora Participating Area and defined expansion areas ("AP A") in the Prudhoe Bay Unit. 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. ih Avenue, Suite 100, Anchorage, Alaska 99501 on July 24,2001. Concurrently, the Commission heard testimony concerning proposed pool rules for the AOP. 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 was requested by the Commission at the hearing and has been provided to the Commission. This supplemental information was submitted by letter from BPXA dated July 31,2001. FINDINGS: 1. Commission regulation 20 AAC 25.402 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, facility site, reservoir, project, or similar area. ) Area Injection Order No 22 September 7, 2001 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. Page 2 Concurrent to this order, the Commission revised pool rules governing the AOP (Kuparuk River Oil Pool) by Conservation Order 457. The AP A is located in portions of Township 12N-R12E, and T1lN-R12E, Umiat Meridian, on Alaska State Leases ADL-28255, ADL-28256, ADL-28257, ADL- 28258, ADL-28259, and ADL 28261. The APA is located within the current boundaries of the Prudhoe Bay Unit ("PBU"), North Slope, Alaska. BPXA is the operator of the AP A. BPXA, Phillips Petroleum, Co., ExxonMobil Corporation, and Forest Oil are working interest owners ("WIOs") in the AP A. The State of Alaska is the surface owner. The reservoir interval for proposed injection is the Kuparuk River Formation. The AOP is defined as an accumulation of oil that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12. 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. Original oil in place ("OOIP") is estimated to be 110 to 146 MMSTB. Waterflood is part of BPXA current development plans. Additional recovery by waterflood over primary recovery in the AOP is estimated between 15-25% of the original oil in place. Production rate peak for the proposed development plan with water injection is estimated at 14,000-17,000 bopd with a maximum water injection rate of 20,000- 30,000 bwpd. 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. Produced water from PBU Gathering Center 2 will be injected into the AOP. Water injection operations at the AOP are expected to be conducted at pressures above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Based upon S-l 0 1 leakoff test, the fracture gradient within the Kuparuk formation of the AOP is approximately. 73 psi/ft The Kuparuk River Formation at the AOP is overlain by the Kalubik, HRZ/CMl 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/ft. Underlying the Kuparuk River Formation is the Miluveach/Kingak shale sequence. Leakoff tests in the Kingak shale show a fracture gradient of approximately .85 psi/ft. ) ) Area fuj ection Order No 22 September 7, 2001 16. 17. 18. 19. 20. 21. Page 3 Expected average wellhead injection pressure is 1800 psi with present facilities. A surface booster pump may be installed at a later date to increase wellhead pressure and ensure injection rates. BPXA plans to keep injection pressures below 5500 psi at 6700' TVD, under the fracture gradient of the confining intervals. This roughly corresponds to a maximum surface pressure of 2600 psi. BPXA is concurrently requesting conversion of S-lOl to water injection for support of current producers (S-l 00 and S-l 02). The development of the proposed AP A 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. There are no freshwater strata in the area of the proposed injection. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An Area Injection Order is appropriate for the project area in accordance with 20 AAC 25.460. 3. There are no freshwater strata in the AOP area. 4. The proposed injection operations will be conducted in permeable strata, and may involve injection above the parting pressure of the Kuparuk Formation in the AOP. The injection pressures will be maintained below the fracture pressures of the confining intervals. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 6. Implementation of an enhanced recovery operation involving injection of produced water from the Prudhoe Bay Unit will preserve reservoir pressure/energy and enhance ultimate recovery. 7. 8. The proposed AP A water injection project will result in approximately twenty (20) percent increased recovery over primary production alone. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project ) ) Area Inj ection Order No 22 September 7, 2001 Page 4 or disclose possible abnormalities. 9. An Area Injection Order enabling enhanced oil recovery activity will not cause waste nor jeopardize correlative rights. NOW, THEREFORE, IT IS ORDERED THAT the underground injection of produced water pursuant to the project described in BPXA's application is permitted in the following area, subject to the conditions, limitations, and requirements established in the rules set out below: Umiat Meridian Township Range TI1N R12E T12N R12E Sections N ~ Sec. 3 S ~ Sec 17; SE ~ Sec 18; E ~ Sec 19; All Sec 20; All Sec 2l;W 1/2NW 1/4,S ~ Sec 22; SW ~ Sec 23; SW ~ Sec 25; All Sec 26; All Sec 27; All Sec 28; N ~, Se ~ Sec 29; E ~ Sec 32; All Sec 33; All Sec 34; All Sec 35; N ~, SW ~ Sec 36 Rule 1 Authorized Injection Strata for Enhanced Recovery Injection is permitted into the accumulation of hydrocarbons that is common to, and correlates with, the interval between 6765'- 7765' measured depth ("MD") in the Mobil Oil Corporation Mobil-Phillips North Kuparuk State No. 26-12-12 well. Rule 2 In.jection Pressures The injection pressure shall be limited to 2600 psi at 6700' tvdss, so as to ensure fractures do not propagate into the confining shale intervals. Rule 3 Fluid In.jection Wells The underground injection of fluids must be through a well permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Rule 4 Monitorin2 the Tubin2-Casin2 Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. Rule 5 Demonstration of Tubin2-Casin2 Annulus Mechanical Inte2rity 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. ) Area Injection Order No 22 September 7, 2001 Page 5 Rule 6 Notification of Improper Class II Iniection The operator must notify the Commission if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operator's responsibility. Rule 7 Other conditions a. It is a condition of this authorization that the operator comply with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata. Rule 8 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 in an increased risk of fluid movement into a USDW. DONE at Anchorage, Alaska and dated September 7,2001. (~DuLL' ~x4u Cammy °tit~sli Taylor, Chaj{t) Alaska Oil and as Conservation Commission Ç{):D/~T' S ,W ~c .. anI. eamount, ~ommIssIoner Alaska Oil and Gas Conservation Commission ~Mr~ Julie M. Heusser, Commissionner 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 nrd 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 1 O-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., lOth day after the application for rehearing was filed). PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SO BLDG 1050 CONNECTICUT A V NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 2121 NORTH BAYSHORE DR #616 MIAMI, FL 33137 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN,IL 61820 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH PO BOX 370 GRANBURY, TX 76048 H J GRUY, A TIN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV & NATRL RESOURCES, OIL & GAS PROGRAM 2050 W MAl N STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 ) 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 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LlBRARYIINFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 IOGCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SO, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY PO BOX 576 HOUSTON, TX 77001-0574 RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MURPHY EXPLORATION & PRODUCTION CO., BOB SAWYER 550 WESTLAKE PARK BLVD STE 1000 HOUSTON, TX 77079 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 ) OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARK ALEXANDER 7502 ALCOMIT A HOUSTON, TX 77083 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 C & R INDUSTRIES, INC." KURT SAL TSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 ) PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 WATTY STRICKLAND 2803 SANCTUARY CV KA TY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 1655 80901- TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE,WA 98101 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 ... ) RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 FOREST OIL, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 ) JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 715 I ST #4 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET 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 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 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 ANADRI LL-SCH LU MBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICNCANADIAN STRA TIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 ) ALASKA DEPT OF LAW, ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 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 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 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 BAKER OIL TOOLS, ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 UON ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 ) GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 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, DIV OF OIL & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE 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 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 ) US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERA TNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ) US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 ASRC, CONRAD BAGNE 301 ARCTIC SLOPE A V STE 300 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 OPST AD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 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 POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHA VELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 ) HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, PRESIDENT TONY IZZO POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, KEVIN TABLER POBOX 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 POBOX 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 770471 EAGLE RIVER, AK 99577-0471 RON DOLCHOK PO BOX 83 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ, AK 99686 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ,AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 ) KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 COOK AND HAUGEBERG, JAMES DIERINGER, JR. 119 NORTH CUSHMAN, STE 300 FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 ::t:t: 1---\ UJ 1-9-05 Kovac to AOGCC Jim Regg -BP UP') ) ~llþject:1J9"05~ÖyàêtO>~ij)û€)CJi11).l$eggt~r1--!p~~!~ }f'J0Qlll: Marc and Shannon Kovac <yesno 1 @gci.net> Dâte:Stu'l,09Jat1200514:54:48 -0900 To: ,JodyCoI9J:1).bie.<j()~y~cQlöm.bie@Gldniin.$Ülte.ak. us?> .CC:ChuckHatnel.<HaÌ11elChuck@cs.cötn?> 1//9/05 Jim Regg AOGCC, BP GPB WOA Field Operation Update 1. Recent ADN article. BP pays fine for A22 and Hll. http://www.adn.com/front/story/5995963p-5892128c.html H 11 presented the same conditions as A22 and could have resulted in a similar fate as A22. 2. On 11/22/04 Anna Dube, BP Well Integrity Coordinator, Emailed all GPB management stating some well pressures were not recorded by the Field Operators as required by AOGCC. The well pressures were actually recorded as required, on time, by the Field Operators, but flaws exist in the BP software program that prevent the updating of the reads in the computer for some well-pads. When confronted by the Operators, Duby stated she would not write a retraction or correction to management and she further refused to add to the reports that they could be false due to software issues. 3. Previously BP management wrote disciplinary letters on four operators who's safety systems for SSV valves were found to be in the wrong position, even after management agreed the operators can not monitor all wells under their control, or prevent supervision, contract staff or maintenance staff from entering well houses. These are all examples of management creating misinformation to blame operators for H 11, E and G-pad incorrect or missing records, and safety systems found in bypass by AOGCC. Management refuses to accept responsibility and continues to report to upper management and AOGCC all field violations are a result of Operator error or misdeed. 4. Last week, about the date 1/1/05, the new BP Optimization Engineer stated in the Field Operator's morning meeting that the operators would now be required to operate 10f2 1/10/2005 2:20 PM 1-9-05 Kovac to AOGCC Jim Regg -BP Dr -', : "troubled wells". He stated the current operating policy allows for this. Operators must closely watch these wells and if continued pressure issues exist they are then asked to inform the Field Optimization Engineer and integrity tests will be scheduled. This is not what the Field Operators understood and were trained to do after A22. The Operators were confused and stayed after the meeting to try and understand this change of course. It is obvious BPnow has returned to the same way of doing business, creating the same risk to the workers, as was the case before A22. More Operators are being hired which is a major improvement after A22 disaster, but requiring new operators to stay closer for a longer period of time to operate troubled wells with known pressure danger will not improve risk to the workers, it makes it worse. I can't believe AOGCC is allowing this arrogant dangerous behavior to exist after the lessons of the A22 disaster were experienced. Production, profit and maintenance avoidance to save on budget is more important to BP than Health Safety and protection of the environment. Marc Kovac BP Field Mechanic PO. Box 2973 Seward, AK. 99664 907 -224-8722 yesno 1 @gci.net 20f2 1/10/2005 2:20 PM ::t:t:: ~ N [Fwd: Supplemental Data requested for AlO 22 mod] Subject: [Fwd: Supplemental Data requested for AIO 22 mod] Date: Fri, 07 Mar 2003 18:37:03 -0900 From: Jane Williamson <Jane- Williamson@admin.state.ak.us> To: Jody J Colombie <jody - colombie@admin.state.ak.us> Jody, These are all the colored slides for AIO 22. Jane Subject: RE: Supplemental Data requested for AIO 22 mod Date: Fri, 7 Mar 2003 20:12:01 -0600 From: "Paskvan, Frank A" <PaskvaFA@BP.com> To: "'Jane Williamson (E-mail)...<Jane_Williamson@admin.state.ak.us> cc: "Copen, James D" <CopenJD@BP.com>, "Beuhler, Gil G" <BeuhleGG@BP.com>, "Young, Jim" <YoungJ3@BP.com> Jane, Enclosed are exhibits requested in color. Jim sent earlier the cumulative voidage data by fault block. So I believe that is all the information requested in order to close the record. Please let me know if there is any other needed. . . Regards, Frank «Aurora AIOmodExhibitsF.ZIP» m..-' "....,,- ,,- mY ...'-, r-"---- ----- -- ---------------- T ----..------_._------------- ----------- ------------------------ ------------------------- -------------,---- --------------------------------- ------------- -------------- -, -,-, I ! Name: Aurora AIOmodExhibitsF.ZIP , i ~Aurora AIOmodExhibitsF.ZIP~ T~pe: Zip Compressed Data (application!x-zip-compressed)f t,.."""",-"",,,,,,,,,,,,"",,,,,,,,,,,,,,«",,",,,,,,,,,,,,,,,,,,,,'"",'«""'"","-""W««W","""M""""X""""'"M'''''''"I"~,~~,~~!.~~,:-"..~,~,~,~~~""""""""""",,,'"","",",x'"""""',,,",,","",,,,"""""", ' "" """"",^,"',,,,,,,,,,""",'",,,,,,,^,,,'''",''''""'',,,,,","",',W"""",",",,,,,,,,,,,",,,,,¡ 1 of! 3/8/2003 9: lOAM Exhibit 1-1 Aurora Location SANDPIPER UNIT MILNE POINT UNIT COLVillE RIVER UNIT ,.J - T - - r~ -:y ~°1:;::~,\ rJ{---C-- -~ , ~ !-, -~J i --- '~--r:l r- ~ %.~ . , L '-- 'r I . '1- l f ~ AURORA POOL .. '--J'---' ~1 1-~rQ ,-JQ -L. r1 :' J--' l.~-. . -- L........ ~ , r a -.J KUPARUK RIVER UNIT '1 ( Lï .. ,--' NORTHSTAR UNIT ¡---L-l . ., -, Q ~~aLL þ ~ -~,-.\ \r~¡ L ,~ . . . .~ '-"'" ~ . PRUDHOEBAYU~ ~ - -..J' I L~J ~' 0 L--- 5 I 1,0 1~ Miles , ----' BPXA Cartoaraohv/4-12-2001/Im14369.dan Aurora Enhanced Oil Recovery Project Exhibit 1-2 Aurora Top Structure wI 114 mi. radii from Injection Wells '-' , \ ~ Aurora Enhanced Oil Recovery Project ~~---- 14 12 10 J2 0 en E 8 E ~ 6 ~ 4 2 0 2000 ----- I ' i ~ .:! .,1:, I' A ! ! J ,/- -H'! i I ~ ¡ I,;ryi,:. I I ! ! Addendum to application exhibit V-I Represents latest EOR forecast i r i /~: I I ! I I i 1 . '!i!'~~ ! ' 2005 2010 2015 -Mllnjection Rate mrnscf/d - RMI Rate nTnScf/d -- EOR Oil Rate bpd 2020 2025 1050 900 750 C) Q. m 600 .æ as a:: 450 ð a:: 0 3QOw 150 ~ 0 2030 :::am I» >< fIIIÞ::T CD -. .,,~ 0" l1l8I< CD . n~ I» tn fIIIÞ mstbd Production mstbd or mmscfd ~ ~ ~ ~ ~ I'V ~ 0> (X) 0 I'V ~ I I'V ~ 0> (X) 0 I'V 2000 '" 2000 2001 ' ; - 2002~, \... ~ 2002 2003 - 2004 - Y 2004 2005 - I 1 0 - 2006 - .i» 2006 - 2007 ~ ~ ~ Q c » - w œ œ - ~ c 2008 - -0 ~ ~ ~ ~ 2008 - a 2009 - a 5" "U a. r» Ã1 a. ---.. ~ c: c:= 2 2010 - ~ å § ~ := 010 - ~ 2011 - õ. g ~ g fit + 2012 - , ~ g. 3t 2012 - ~ 2013 - I 0 :;0 2014 - ",' 8. 2014 a 2015 - "tJ - Co 2016 - a 2016- ~ 2017 Co õ. 2018 ~ ~ 2018 :;. 2019 - ~ ~ 2020 - :I 2020 - I I 0, I' g 2021 - ." sa. 2022 - ~ 2022 s: ;tI 0 m CD -s:=o 2~3- n - -0 ;tI 2024 - = 2024 a 0 2~5- ~ ~ ~ 2026 - 2026 g a 2~7- ~ ~ ~ 2028 - 2028 ~ a 2029 - ~ ~ ~ 2030 ~ 2030 :::J ¡ I ~ ~ ~ I'V I'V ~ ~ :::J 0 ~ 0 ~ 0 ~ ~ 2 mstbd Injection or mmscfd ::0 (1) 0 * -< "'0 .2. (1) Sl ( ( Exhibit VI-1 b Integrity Report of Offset Wells W II S112 offset e ~~.: Pro~em 5-10A 843 Note: Does not show up on the WOA 81 Well Report. 617 Slow Tubing x IA communication, MITIA's pass. Status Planned Action .¡. -- No tubing, perfs are cemented off None 5-24 On injection Low OA FL - Priority 1 -'"......./ 5-25A 401 Tubing x IA comm, tubing hole at 7062' 51 as of 10/00, RWO scheduled 1. DHD: Check OA FL every 6 months. 5-26 1,280 Slow IA x OA communication Wajvered JAxOA comm [10/13/02] See "137 List" 5-32 925 Slow IA x OA communication Temporary IAxOA comm waiver 1. WDE: Eval for OA downsqz- issued 03/15/01 done r Down SQZ on hold] 5-33 564 None None None 5-35 1,192 None None APE requested TlFL, rapid production rate loss 5-36 397 None None None 5-37 1,139 None None None 5-38 568 None PAL Eval possible IA x OA ~ communication (07/14/02) 5-42 883 T x IA comm, llFL failed 11/2/02, FT5. None ,Obj: Eval for TxlA waiver 5-43 846 None None None 14 ------T 12 10 J2 0 t/) E 8 E ~ 6 ~ 4 2 0 2000 ----~ Addendum to application exhibit V-I Represents latest EOR forecast J ! 'I" I 'I t'\il i,:, i I I ~ I i I,. ! I' . i 1 ¡ ;Ij~ ¡ ,~¡ I i'::, ¡ !:., ¡ 'IlL' ¡ ! ! ! .. -.... i ! l i i) : --- 2005 2010 2015 - - I - MI I njection Rate f1111Scf/d - RMI Rate nTT\Scf/d - EaR Oil Rate bpd 2020 2025 1050 ~' 900 750 Q 0- m 600 $ CG a:: 450 ð a:: 0 3QOw 150 ~' 0 2030 Exhibit IV-1 Comparison of Aurora and Prudhoe Bay Fluid Composition 50% 45% 40% u_-- 35% ---- 30% ----- c 0 ~ I! 25% ---- u. CD Õ :& 20% - 15% - 10% 5% - 0%. '+ I 1 2 3 4 - .,..-=--- -.--.... Prudhoe Composition . Aurora Composition , :,;;;("~'0~7~~0~:z,_, . ,Å Å ,,/C; Å , '~"~:::::'~::::~,.~~-~~-==-=~~~/ . 4:"'> 5 6 10 11 12 13 14 15 16 17 18 19 7 8 9 Component Number Component number Name 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 CO2 N2 C1 C2 C3 I-C4 N-C4 I-C5 N-C5 C6 C7 C8 C9 C10 C11-13 C 14-19 C20-26 C27 -35 C36+ ~ ~ Aurora Enhanced Oil Recovery Project Exhibit VI-1 Offset Well Integrity: Wells within 1320' of injection ~I S-112i only current AOP injector w/offsets within 1h mi. radius Well Meas Subsea TOC Est. (30%) Job Well Status Depth at ,Depth at Offset, (30%wash ,Cement abo\e . Flags Name Name Well Status Desc TKUP (ft) . TKUP (ft) (ft) out) MD lAOP (ft) ? 5-112 GL-O Pre-Prod. Inj-Heel 6,852 6,614 1 3,168 3,685 S-36 GL-O Oil Well On Gas-Lift 6,917 6,620 397 4,678 2,239 S-25 SI-W Water Injector 6,805 6,620 401. '1,796 , 5,009 S-33 GL-O Oil Well On Gas-Lift 6,725 6,620 564. 4,666 2,059 . ' S-38 GL-O Oil Well On Gas-Lift 6,863 6,620 568 4,584 2,279 - - - - - 5-24 P&A P&A 7,282 6,620 617 4,933 2,349 S-10A 51-5 T/A 6,801 6,620 843 5,288 1,513 S-43 GL-O Oil Well On Gas-Lift 6,938 6,620 846' 2,080 4,858 . , , S-42 GL-O Oil Well On Gas-Lift 7,210 6,620 883 2,962 4,248 , . S-32 SI-O Oil Well On Gas-Lift 7,454 6,620 925 5,097 2,357 S-37 GL-O Oil Well On Gas-Lift 6,787 6,6201,139 4,526' 2,261 S-35 GL-OOilWeIlOnGas-Lift 7,204 6,620 1,192 4,781' 2,423 - ,-- - - S-26 SI-O Oil Well On Gas-Lift 6,850 6,620 1,280 4,324 . 2,526 8-112 Gl-O Pre-Prod. Inj-Toe 8,550 6,620 1,723 3,168 : Comment, other . e\Ädence of , confinement USfT top@3250' I , ' . 3X.1ÏJit =-5: Aurora Areas (Exhibit 1-5: June 15, 2001 Pool Rules and AIO Application with Aurora wells to Feb-2003) ~ " ' I I , - ¡-- I , I 1 " ... , M'I .~-~:~~'(~: ---~---~ ,;~. 112i ~9 ! South East of Crest Block "'"-' I ~ -- - I . S.113 " - Beechey Block ~ ~:/. I '- ,-,--_.._--,_..._-~-~------ - West Block V-200 Block . . ~ =tt: ~ ~ .~ .) file:// /Untitled flY oung, 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 detennined 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/ft. In order to stay below the breakdown pressure of the above mentioned formations & assure that produced water injection will be contained in the Kuparuk fonnation, maximum bottom-hole injection pressure in the Aurora Pool will be limited to 0.83 psi/ft. 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 10Opsi, 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-10li 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 1 of 1 9/4/01 5:02 PM Re: [Fwd: FW: Aurora Pool Infonnation Request] (. ) 4Þ) ,'f Subject: Re: [Fwd: FW: Aurora Pool Information Request] Date: Sun, 19 Aug 2001 13:53:37 -0800 From: "Camille o. Taylor" <Cammy_Taylor@admin.state.ak.us> Organization: DOA-AOGCC To: Robert Crandall <Bob - Crandall@admin.state.ak.us> CC: Dan Seamount <dan - seamount@admin.state.ak.us>, Julie Heusser <julie_heusser@admin.state.ak.us>, "Jody, \"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 > > > > > > > > > > > > > > > > > > > > > > Gordon: > > I e-mailed Steve and Janet as > data the last time we talked. > pressure data from the Aurora > > Bob Crandall > > > > > > > > > > -------------------------------------------------------------------- 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. should be sent to you on Monday with a transmittal letter. You receive MPU data from Janet Weiss this week. Gordon These should -----Original Message----- From: Robert Crandall [mailto:Bob Crandall@admin.state.ak.us] Sent: Tuesday, August 14, 2001 11:46 AM To: Pospisil, Gordon Cc: Seamount, Dan Subject: Re: FW: Aurnr;:¡Pool Information Request we discussed. We also discussed pressure Do you want to submit any additional area? "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. 10f4 8/20/01 II :40 AM Re: [Fwd: FW: Aurora Pool Infonnation RequestJ(...) ~ > > > > 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 > > > > > > > > > > > > > > > > Gordon: > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > I hope this is useful. > > Bob Crandall > > > > > > > > > > > > > > ~ 20f4 -----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 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 peti tion 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 the hearing RFT data was used to characterize the initial pressures, are there static or PBU data which are representative of initial conditions also? "Pospisil, Gordon" > > > > > wrote: -----Original Message----- From: Pospisil, Gordon Sent: Thursday, August 02, 2001 8:38 AM To: 'Crandall@admin.state.ak.us' 8/20/01 11 :40 AM Le: [Fwd: FW: Aurom Pool Information RequestJ'- ) ~) > > > 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 wi th 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 > > > represen t the owners or opera tors of Kuparuk River Uni t or Milne Poin t > > Uni t > > > 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 Uni ts 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 > pri vileged > > > 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. 30f4 8/20/01 11 :40 AM .e: [Fwd: FW: Aurora Pool Information Request:&' ') "J > > > > > > Gordon > > > 564-5769 > > > > > > EMAIL AS FORWARDED: > > > Fred: > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > > 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. > > > > > > > > > > > > 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 Uni t. If you have any questions or comments please call me at 793-1230. Thanks Bob Crandall 40f4 8/20/01 11 :40 AM E: FW: Aurora Pool Infonnation Request 0' . ) ) 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. should be sent to you on Monday with a transmittal letter. You receive MPU data from Janet Weiss this week. Gordon These should -----Original Message----- From: Robert Crandall [mailto:Bob_Crandall@admin.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. lof4 8/16/2001 1:02 PM E: FW: Aurora ~ool Infonnation Request > > 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 20f4 8/16/2001 1 :02 PM :: FW: Aurora Pool Infoll11ation Request . . ) ) > Uni t > > 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 > > at: tached) . > > > > 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 > > .condi tions. > > 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 > > > > E~IL 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. ,of4 8/16/2001 1 :02 PM ~: FW:. Au!ora \.001 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 > > uni ts 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 of4 8/16/2001 1 :02 PM E: Request for lnfonnation Relating to Aurora Pool R ) ) 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, JanetL" <WeissJL2@BP.com> CC: "Seamount, 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 [rnailto:Bob_Crandall@admin.state.ak.us] Sent: Tuesday, August 14, 2001 11:23 AM To: weissjI2@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. 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. We 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 ~quest for information relating to Aurora Pool Rules ) ) 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 CC: "Seamount, 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 Iuest for Information Relating to Aurora Pool Rules ) ) 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: weissj12@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. 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 We 8/16/20011:03PM =+t: ....... 0 . ,. i . ) PHilliPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P. O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 17, 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 API 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. 1. 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. 2. Initial Oil Gravities Attachment 2 uses that same data set and shows the reported API oil gravities from the same wells prior to start-up. The average gravity, as shown on the graph, is 24° API, which is also reported as the average oil gravity in Attachment 3. 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 occulTence 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 eastem 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, #~2 , John Braden Kuparuk River Unit Surveillance Engineering Supervisor RECE\VED AUG 2 0 Z001 Alaska Oil & Gas Cons. Commission Anchorage Cc: Don Ince Gordon Pospisil, BP (¡.) (¡.) ..... ..... 0 en 0 0 :::::1.., I 1: : I 18-03 - 6/17/1981 - DO,Csand 1E-06 - 10/21/1981 - 00,8 sand - IE-07 - 10/29/1981 - 00,8 sand 1C-08 - 5/21/1981 - PBU, C sand 18-05 - 8/7/1978 - S8HP, C sand 18-02 - 6/26/1981 - DO, 8 sand 1E-03 - 10/19/1981 - 00,8 sand lE-02 - 8118/1981 - 00.8 sand IE-OI -8/21/1981 - PBU, 8 sand IE-OI - 8/2011981 - DO, B sand lE-06 - 9/111981 - pau, a sand 10-05 ... 6/12/1981 - PBU, C sand --" f' iii lC-06 ... 11/30/1981 ... P8U, C sand -"-"r ',If ''''''IIi"'' 18-01 - 11/28/1981 - DO, a sand ."rnod"""'-\11 18-07 - 11/24/1981 - P8U, 8 sand" -...,'I.....-..T-" "IIIII8IIIdII 18-01 - 11/29/1981 - P8U, 8 sand ~--_..--,---IL----_..,--"- lE-03 ... 10/20/1981 - P8U, 8 sand - &,'1 -'"...........,,----,- 18-05 - 8/6/1981 - SBHP, B sand ~"::I~I::':II:~i,IIl,iIIo..J........." pressure, psia (¡.) (¡.) I\J I\J 0 en 0 0 (¡.) (¡.) 0 0 (¡.) (¡.) en 0 .... """"I 10-06 - 6/9/1981 - PBU, B sand IIIIIm:--:::::~: ....~,'u=:,:~~-~ 18-08 - 11/28/1981 - P8U, 8 sand ~...........II1!...I...'I._---~ 18-08 - 11/27/1981 - DO, B sand "'. I., ".._..__...n,.."",' "..,I.... 1E-04 - 9/3/1981 - 00,8 sand p..... . ". _::::::::':::ma lB-06 - 11/21/1981 - DO, B sand ~', 'fl"" 1E-08 ... 11/1/1981 ... 00,8 sand .. ,L...............,......__Ln,,,,,,,,,,,..J 1D-03 - 8/3/1980 - PBU. B sand ....... " ",,--- '" ' :.L lE-04 - 8/4/1980 - PBU, C sand L:::.::.::::::::n""':~ I ,_n'mn".,u",,_n..-D..-. lE-07 - 8/25/1981 - P8U, B sand- ::r:::::::::....:..::T,,::"'.~,~,,:,.;:",,==-J.::_"..m'~~ 1C-04 - 1/24/1981 - PBU, C sand -......"""""""",-, """.'^'UiA,-f",ua::!IJ:!!iI lB-06 - 11/20/1981 - PBU, B sand þ--.__n"....._,,_J"'.;t:"1'£T.=::=IJ::L::"-=-~:""""'::::::.:J lC-05 - 2/27/1981 PBUóCsand m",..:::l:!!!IIIIII '"' '..- .n--t~.._","""",, lC-Ol ... 5/9/1981 - PBU, B sand r-.....nmo.,::."oiI"..\mm¡¡(~\\I\l,;C~'~::C:;I~ lC-04 - 3/10/1981 P8U, C sand. ' ~".... ."'.' -.,".. ""..'" 1.,,, .~ lB-03 - 6/18/1981 - PBU. C sand , I.:,,-::.ar~:~ IE-02 - 8/19/1981 - PBU, B sand II..". n_.nm'_m_'~1 1,...-.. "- IE-03 - 11/5/1981 ... PBU. B sand In,,~,,~_,,,,,,,,,,,,,,,,",,,,,,,,-;'''~,,,",--''''''''!',,,..m..............J 1B-02 - 6/24/1981 ... P8U. 8 sand F- ..,.. nnm ~ILll._- 1C-06 - 4/28/1981 - P8U,C sand , "':..-m......,,n...._n....'i'~ lC-02 - 7/7/1981 ... P8U. C sand t--n.. In.n___L , ~ lE-04 ... 9/4/1981 - PBU. B sond::::V:-.':..n .4)[1...::.:.01....,11 ..~"..., l..,nn..D-.J IA-08 - 12/1/1978 ... P8U, B sand L- 10-02 - 6/14/1981 ... PBU, C sand""', ,nn:"', h,..í:',:~~e~~~II~:~~"hm!ìr~,::o~ 10-08 ... 5/1/1978 - PBU, B sand \L..-,-----,Ln_n.u.. n,1.... ~ IE-08 - 11/2/1981 ... PBU, B sand ~. .I..l.-_-_.J...- ---. 1E-08 ... 8/29/1981 - PBU, B sand ~' --eu~u'm_---_.. _.. . 'dI' ...m"..'n_' ~ 1 D-07 - 6/7/1981 - P8U, 8 sand ,.............. nn'lf' . 'i l_._~...m~~~...~w~n~f _...~"u" ..~ 18-03 - 6/1/1981 ... PBU. B sand ..'~~:r,]["c;¡p"::]'~:,,u-J::n"",',.n..=:~~~:~=.:::, 1A-12 ... 7/31/1981 ... P8U, B sand l.mu.u'\7",r::"\!."_J.h~n~: :::::::::c:ID.:=:r::::n.:::~::::: ~: ' " C "C I» ... C " AJ <" (þ "C ... ::!. c: 0 ::;:, ... -" r+r+ 0 "'tJ tJ) a r+tJ) I» en ::1c . ... c (þ "C ø I» r+ 0) t\) 0 0 ::t en en ~ II!!t ~ .lN3~H~V 1.1." ( . p ~ ..II. P API Gravity, °API ..II. I\) ~ p I\) ?1 I r---- " .. lB-03 - 6/17/1981 - DO. C sand 1[-06 - 10/21/1981 - DO, B sand 1[-07 - 10/29/1981 - DO. B sand IC-08 - 5/21/1981 - PBU. C sand 18-05 - 8/7/1978 - SBHP, C sand lB-02 - 6/26/1981 - DO, B sand 1[-03 - 10/19/1981 - DO, B sand - . . ,- I ----,---_._-,~ --- 1[-02 - 8/18/1981 - DO, B sand . , ,-- ---JiL__- 1[-01 - 8/21/1981 - PBU. B sand - ~L---:::I:::-~-nt::::c:--::::--::T:=:J:1IIII 1[-01 - 8/20/1981 - DO, B sand JIIøL~._~..~,~_J 11181111r---",..-"" L.__..__~~=::::_--_.....:....:]!::n\1!::þ=;:_-_J:JL-:-:m¡: 1[-06 - 9/1/1981 - PBU. B sand 10-05 - 6/12/1981 - PBU, C sand lC-06 - 11/30/1981 - PBU. C sand ~--I< -...-::::.:::::::- __r:::::::::.....-------.---.'I-- -..----__.,_1 lB-Ol ... 11/28/1981 - DO, B sand ~f.:-C-::~:- .~-¡;;;,,;:-------~~~~ lB-07 - 11/24/1981 - PBU. B sand' ,::'C'-:lL" 1_-""'-----IIII------'-~":;-~-'""""'""~'JJ~lm~ lB-Ol - 11/29/1981 - PBU, B sand - 1[-03 - 10/20/1981 - PBU. B sand r.,--<~---""",\;I\..".;!b--<........{~<;<:::'c:::'L.:=---..:::::._-,'=:::::::::::_,::l::::,c:~~=.JOC:::::r~ lB-05 - 8/6/1981 ... SBHP. B sand 10-06 - 6/9/1981 - PBU, B sand lB-08 - 11/28/1981 - PBU, B sand ~:x:=x::.:.:.u::::- ::::::~:::JIi.-.¡¡p-,:::::::::::::::::::"::::::l::::::n:::::_" ..L......- -...____,11___.__- lB-08 ... 11/27/1981 - DO, B sand ~=::::':::..J...-II ' -I. --,-"""",<-_.-.-...."~~.._~","-<--<.,--"""="'- 1[-04 ... 9/3/1981 - DO, B sand "---:--Jr.- -i: -"~"~,-----..__A._-:",::::::~~'=-o...r;;.~~iii1ftU_~ lB-06 ... 11/21/1981 ... DO, B sand \IIII'I::,:::::T:t::"::J.iJ,"T .. - --':;:::::::L:-:,"'IIJI--:::--::~ 1[-08 - 11/1/1981 - DO, B sand ~----.....J--._.._--.....---,-_O!Jbr:x("___L='::'::':::=~:::::=_'!r!I~¡¡¡¡~:¡¡n¡¡mJ 10-03 ... 8/3/1980 - PBU, B sand !-""'j-_;',JlWl~'~"d<_~.-wm~_~=_"~~''''' ... ,"""""k~- 1[.,.04 - 8/4/1980 ... PBU, C sand 1[-07 ... 8/25/1981 - PBU, B sand L----_~'~'_d~R,.---~--,"xP"""",."""""""""",,,~~~ lC-04 ... 1/24/1981 - PBU, C sand ~;;Jœ.w¡~,"~ ,," ---....-,----,----"'!;Ji<'mlÆ!u.;..;;;;;;~,~ lB-06 - 11/20/1981 - PBU, B sand ;L\HL_"L~~::::::::J.:::::::::::;¡¡¡~ìDII1í'~-~~""~ lC-05 ... 2/27/1981 - PBU, C sand lC-Ol - 5/9/1981 - PBU, B sand lC-04 ... 3/10/1981 - PBU, C sand 1 B- 03 ... 6/18/1981 - PBU, C sand 1----....-,-."............ ,,,,-,,,,,,'---..\:un..... ;""".._..._-,--_u-.- _u""-----,- 1[-02 - 8/19/1981 - PBU. 8 sand ~:::':::J:(:x::::==:'~_...""~..._..",---'::'::~::==::::::-~:~=::=:::::::::Y;¡¡OO¡¡¡¡::',;;;~¡¡" 1[-03 ... 11/5/1981 - PBU, 8 sand ~"...'.___m--_-,L_"nc',.._.""""""",-,"--,-,>_!'f'"M'--'",","" ;iL-........,.",¡..... lB-02 ... 6/24/1981 - PBU, 8 sand 1 C-06 - 4/28/1981 - PBU, C sand lC-02 ... 7/7/1981 - PBU, C sand 1[-04 ... 9/4/1981 - PBU, B sand ~~:¡¡rl":.:.'!h:~;!I¡Jii:.;¡;;;~~,"""""",,,,,,,,,,,,,,,, lA-08 ... 12/1/1978 ... PBU, B sand 10-02 ... 6/14/1981 - PBU, C sand 10-08 ... 5/1/1978 - PBU, B sand 1[~O8 ~ 11/2/1981 ~ PBU, B sand .. ~~::::~~:~~:~~:~--':<"'~==~d 1[ 08 8/29/1981 PBU, B sand þ-...YT:1J[JIC:::X:::~,..__...",¡~~~, 10-07 ... 6/7/1981 - PBU, B sand lB-03 - 6/1/1981 ... PBU, B sand 1 A-12 ... 7/31/1981 - PBU, B sand l .lN3~H~V .l-7'itt (., (..) 0 ^ C "0 D) ..., C "'O^ ~. ::u Q <. -CD 0 ..., en C 6)::J ;:¡.¡:::¡: I» C:"'O "'0 -. (j) ñ3 < ~ ~ CD ..., D) c.o CD c.o ..., D) < ~ II I\) .þ. 0 » "'C ~l ~) , \ " 4' ~TT ACHMENT 3 1 he ^mcrican AS'IOciation of Petroleum Geologists Bulletin. V. 67. No.6 (June: 1983). P. 1014-0000,14 Figs. Geology and Regional Setting of Kupamk Oil Field, Alaska1 GEORGE J. CARMAN2 and PKfEK HARDWICK3 ABSTRACT The Kupamk 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. Tbe 24° 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 Pmdboe 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 piDCh-out and truncation of tbe reservoir at a local uncon- formity along tbe southern and western flanks of a southeast-plunging antiform. Structural dip closure exjsts along the nortbern and eastern flanks. Tbe reservoir sand- stones occur witbin sequences which become cleaner and coarser upward, and are thought to be shallow marine in origin witb a provenam~e to tbe northeast. They are inter- preted to be infrarift sediments on what is now a passive, Adantic-type continental margin. Two of the four major 6thostratigrapbic units mapped within the Kuparuk For- mationexhibit good reservoir characteristics and extend over an area in excess of 200 mil (518 km1). The cumulative net pay in the Kuparuk field ranges up to 90 ft (27 m), and the estimate of movable oll-in-place is 4.4 billion stock tank bbl. There is no, gas cap. The field exhibits a variable oil-water contact ranging from -6,530 ft (...1,900 m) in tbe southeast to -6,700 ft (-2,042 m) in the north. After seeondary waterilooding, the potential recover- able resenes 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. @Copyñght 1983. The American Association of Petroleum Geologists. All rights reserved. 1Manuscript received, May 6,1982; accepted, May 27.1982. Presented at the annual AAPG convention, Calgary, Alberta, Canada, June 1982. 2BP Alaska Exploration Inc., 1 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., 1 Maritime Plaza. Suite SOO, San Francisco. California 94111. Current address: BP Petroleum Development of Spain, SA. Cea Bermúdez. 66 Madrid-3, Spain. The writers thank the management of BP Alaska Exploration Inc.. $ohio Alaska Petroleum Co., and the Atlantic Richfield Co. for permission to 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. Whanon for their specialist contributions to 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 km) north of the Arctic Circle. Its history ofdiscovery-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 U gnu 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 1 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 ExploraHon 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 100year 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 28.8070 for BPAE, 57.5070 for ARCO, 9.6070 for Sohio, and the remainder divided among Chevron, Exxon, Mobil, Phil- lips, and Union. BASIN GEOWGY The principal structural features of the Alaskan Arctic basin are the Barrow arch and the Colville trough (Fig. 2). The Barrow arch, a paleo high that influenced the deposi- tion of pre-Late Cretaceous sediments, is now located just 1014 ;. 6) . 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 'I 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- 0 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 tbe 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. Saga"anirktok 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 aI, 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. Colville 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, sihstone, and mud- stone sequence together with rare thin carbonaceous beds. cr'c OCE'AN "R /--........ ,/'/ ....... // /. I --J) "",7---- ': J (, ~~~ \ -, 1 ,,,0 I ,t" I s~,. I \ '8) ;ï ..ï ~1 ~I ì ¡í if \ -." \ \ \ \ .'00 "DO a~o .'1.18 nG. l-Kuparuk field is lc)(ated about 260 ani (418 kin) north of the Arctic Orcle on north Alaskan coastal plain. It is linked to Trans-Alaska Pipeline system "Via 26 mi (42 Ian) Kuparuk pipe- tine. 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 (1980). 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 dinoflagenates and radiolarians, in addition to which agglutinating Foraminifera and miospores occur. Mainly on the evidence of ponen types, a Campanian to Paleocene age is suggested for this sequence, although it appears probable that these formations are markedly diachronous. "') 1016 "J Kuparuk 011 Field, Alaska . I ~ 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-Iog responses of this group in the type well. The U gnuravik Group is mappable over more than 600 mi2 (1,554 km2) 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. S); however. its contrast- ing lithologies and sedimentary trends warrant a name dis- tinction. -í- ,-- .----- ¡SOu \ 140. ~~ N~.[) 4 13~81N ~ . , ::;.0',"",... ..,' 0"" ,0 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 lone. 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 a1 (1980), 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 £t (61 m) thick. It '.',) ~ ) . George J. Carman and Peter Hardwick 1017 E AUF 0 R T B i~) S E A / ~ -~ lfi ,. -- ~ ~ ,~~j' 0° 0 0 ° 0 aO 0 ", q1 ..°0 ...° .....0 .....° ..",° l,~ l 0° (õ) .." ~ ,,~ ø.. APPIIOJ:. II" " II°ltOt ""tl.o (.,;;'~::":: -700- ~:OWp~~::~::.~~OU. '* D..COVUT WELL 0 L s --.J Mil.. " FIG. 3-lsopachs (in feet) of Lower Cretaceous sequence beneath Arctic plain display thinning onto Colville and Prudhoe highs south of Barrow arch. Kupamk oil field is located within Col"me.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 9070 by weight for these rocks (Seifert et aI, 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 HRZ unit is therefore picked on open-hole logs where the gamma-ray log consistently surpasses ISO API units (Fig. 7). Stable carbon isotope analyses of kerogen from the HRZ unit have yielded ö\Je 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 (Molenaar, 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- ¡an to Albian age. The contact between the HRZ and the overlying lower unit of the ColviUe Group appears to be a 1018 WEST þo6 Rr<.:rNI C ill" £ISIOCfNr PIIOCf.NI' MIOCENF ~, a: :! OLIGOCENE ... a: &ai- ... fOC[NE PAl EOCENE MArSTRICIHIAN CAMPANIAN SAN TONlAN ~ CONIACIAN :) O. ... U TURONIAN C ... ... CENOMANIAN a: U AI BIAN APTIAN BARREMIAN liAU TrRlvlAN VAl ANGINIAN BERRIASIAN TITHONIAN KIMMr.RIDOIAN OXFORDIAN i CAl LOVIAN ., BATHONIAN ., C BAJOCIAN a: ,AAl r.NITOARC ~ PL IENSBACHIAN SINE MURIAN IlrTTANGIAN RHAfTlAN ~ . . ~ NORIAN a: ... ') ~ .,J Kuparuk Oil Field, Alaska eOl VILLE HIGH PRUDHOE HIGH eOL YILLE-PRUDHOE TROUGH EAST 'j' ,:; ..),';::;: ,):' : '; .~ '~, <:~ ',~', : ',' : ' ~u ~IK , F~~ ~ y:~ :~? ~ : : ::~,~:: :';'.i::: ~~; ;-):: ~> ; :;:. '/.~ :~ --.- .--, ,.,~~~.":- ~._~. ~ >-~~ .~~"':~ :.~ >~.~~~'::;"_:: ~,~~=':., -~,_..- : > ': :' : .-.-~ --~;~- - ~., :~< ~",;:.: ~:'.:":"; »:::'.' \;~:~t::.?::~:~~ ,.' ...' , --SAGAVANIRKTOK FORMATION-- .--. ~,,;., '; ... \ ~ . :: : \:~ '.~, ',': <:/ : :::o~: : ': '~::. :': ':: ;,..-: ::'-.:: '~. ~ i:~}: i,:f: :.:: ;~:':: ~\;::: :: ~ ~ .:: ',".: ; ~ ' . .~:; ::.: '::.' :i~:' .:: :~: .'~// ;'): :':~ ~:;~; ".' ::'. :;.-:~ ~.¡.:.~ ;, ':' . .:,'; ;.'.",; '°: : ;. jl:!;:;:~;1ET}~1 ~Z~!~~~!~~~:~~~;;" ~i~?ii~~R;:¡~'\~::::{f~WfJiÆ}~ . -- .------ - -- ...- -" -- ..-.-. .---- ---... -- ----- ~- -- f .-' t ~'''''\.. ~ .\. I. ~ ,. ~--~ 4 . ~ ~ p HIO"'Y eond.n..d Of Ib..ne. by nond.po.ltlcn or eroaton .. - I-~- . ~-.........,.,,""'~ Z C > 0 a= CIC C II ~ '. . ...-~.:z';.. :¡,:.- ~~: ;:::: ~..;¡:: .;:-.:~ ~-..:.: ':; :":.::::,:.~:_.:::;;_.,w~." ,w (" ~:.~.:....J.~~.)fJ.~~~~_.- "\ UGNURAVIK GROUP Aba.ne. .by nond.po81tlon Ab.enee by er0810n Absence by erosion Abaenee by .roaton ./..- ~,. z c - II: 181 . .. 1&1 ... ... III - , --- '- ........ ........ ........ ........ "' Ab.enee by eroalon ;.:)t~(~'~$::~'~;:;~~:' ;¡'.'.' ';';:(;:;:; '-ÃG .'IIVÉR' FuN'::";? ':.':i ;; :'; ::;~(~:;:; :'.':;:!o\~~t.. . ." KINGAK SHALE FIG. 4-Schematic time-stratigraphic section from west to ea.~ across Colville-Prudhoe basin shows that hiatuses occur both above and below Lower Cretaceous sequence. Ugnuravik Group (defined in Fig. 6) is belined to have had a local northeastern sedimentary pro~enaDce and is described as a Barrovian sequence to distin~uish it from Brookian and FJlesmerian 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 ,-The stratigraphic sequence between 5,670 and 5,890 ft (l, 728 and 1,795 m) b.r.t. in the 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- QUAT. '" :;) a:O WW a.,(.) g;e a:: (.) f8,) .) George J. Carman and Peter Hardwick :i NORTHWESTERN NORTHEASTERN COLVILLE- W ALASKA ALASKA PRUDHOE ... BASIN en (Molanaal. 1881; >- C.r.a, a. al18771 (DallarmeR, It 771 (TII'a '.p.rl (/) SOUTII NOIITII SOUTII IIOIITII SOU III /to/IF" SURFICIAL DEPQSITS SURFICIAL DEPOSITS SURFICIAL DEPOSITS GUBIK FORMATION GUBIK FORMATION GUBIK FORMATION >- a: <C I- a: W to- :i J&. NUWOK, lIa B t~~0f ~_:~:::~::O'-- A. ð '1IlNce CIIUKI ~ IC~:~~~~I~'¡."fF COLVILLE GROUP III :I --,._--_.. ..' .. (UNDIFFEREHTIA rEO) :;; ..J 0 U A. ð 'IItlfCe CIIUKI I§ IC""AOEII ILUFF III FOIIMA TlON ... ... :;; g u nAln 'II. nAIU FM, (/) :;) 0 W (.) cI ... w a: (.) a: w ~ 0 ..J . ilL Tlt01l1 "I. Å. 2 --- :; ... ""LI! IMALI! II', 111: ULUI. 'OIl..ATION ~---_.~ ~ 10: ~ ICIIIIIC - I\: ~ IANDSTOlle .8. i ~ Š g IIW'IIACII ,_.nOll :0: . CL." I"ALE .1. r, - ------.-.. -...-. -........ ... TN T UI OllATWACKe "Ill UNIT --~T OK'IIIIUAK - FOII."TIOII ~ () ii) '" 4( a: :;) ""') KINGAK SHALE ICINGAK SHALE FIG. 5-Comparison of lithostratigraphic sequences within and around Colville-Prudhoe basin demonstrates that Ugnuravik Group (defined in Fig. 6) and Kuparuk resenoir correlate to Okpikruak and Kongakut Formations. Whereas source of Ugnuravik Group was from the north, its correlatins were derived predominantly from the south. bik Creek which flows into Harrison Bay west of the 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 J ones and Speers (1975) and Jamieson et al (1980), and probably the lower pan 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 (l, 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 API .020-2000000 KBE = 75 FT. A.M.S.L. UGNURAVIIC GROUP tTTPE WELL) CONIACIAN GR RES AT ~ ~ { } / i \ :1 l-DD. 1 ~;;;- .... ~i~~ <; ~r:~r5670 APTIANI l:1 ¡. ALBIAN ~ ii ': ~ if t 5804 --T;r~-- - , ,,~ ~ .... ~ l ~~ / ) t 1 '"~þ f 1 ~.; ¡ î: } i~ ;~ ( 7; \ n ".. BARREMIAN ¡ ] ~ TO ! 5 ¡' E. VALANGINIAN ~ ~} :,\ }H t ~!' \ ~f ~ { :1' :~ ~ ç i j 1.... ¡ f e. OXfORDIAN 1019 a. j 0 cc: 0 III ...I ...I > ..I 0 U HHZ FM. :i u. 3t: ¡ ::Þ ... C ~ Q a. U :8 :::Þ II. 0 3t: cc: ::Þ <:J CD Ct <C CL - ::Þ ~ :Ie > C <I( a: :::) z C :::Þ J! u. : u <C W > ::Þ = J! :i u. ~ C c:J Z ~ FIG. 6-Lower Cretaceous sequence penetrated in Ugnu State 1 well (API-S0-029-2000900) is formaUy proposed as type secüon for newly defined UgnuraYik Group, Kalubik Formation, Kuparuk 'Formation, and Miluveach i'ormaüon. Locations of geographic names used are shown in Fig.re 2. Many North Slope operators recognize HRZ unit betause of its characteristic fea- ture as a highly radioactive lone. u ~ 1020 Kuparuk Oil Field, Alaska ___0 W'Æ,r COLVILLE 1 KALUBIK CREEK UGNU STATE 1 (TYPE WELL) WEST SAK 1 N. KUPARUK ST. 1 011 REI AT IlL ::s 0 8: ø lie: > C 8: ::s Z c:J ::s .." .. ::s 0 8: c:J ~ > C II: ::s Z e ::s I ~L- "'';~ i'- ,"'~ f COLVILLE HIGH PRUDHOE HIGH LocaTION .ap I: ::.., "..nc.u. 8CALE I1IOT TO ICAL8 _ZOIITAIUI ~-. ~.~~~~ -..-:~: . .._~:.. . ... .;;+// , --., .~..~ .....,p-'-"""" . , . ' .., . . , , + ~. m ="n., E3 :='- ~ ::.~=- D_nT -.... ~ 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 at several stratigraphic levels. Ugnuravik Group is more than 1,500 ft (457 m) thick in axis of Colville-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- miniferal assemblages. The Kalubik Formation is considered to have a marine origin. Kuparuk FormalÍon.- The stratigraphic sequence between 5,890 and 6,262 ft (1 ,795 and 1,909m) b.r.t. in the Ugnuravik type section (Ugnu State 1) is formally pro- SOUTHWEST WEST SAK 15 OR RES AT LOCATION MAP 1-- - . ..... '1 D ~ ~ ~ r=--=¡ WEST SAK 14 WEST SAK 9 UGNU 1 WEST SAK 17 NORTHEAST z ~ 0 ã5 t:: :;) -< .... :::IE < a: ~o II. a: W ED Z m 0 ~ t-: W c( Q. ~ ,,----1 ~ ; a: '-~O LL. a:, Wi :~I ~ ,W' ~ :~ a: ia: c( :W D.. I ~ ~ i g. ~ ; % Z 00 < - w to- > tCI; ::» ~ ...I a: - 0 :::E II. 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 the southwest coeval with mudstone of 0 unit to the northeast. OR RES AT OR Res AT OR REI AT OR RES AT ~ PREDOIIINANTL Y SANDSTONE SIOERme 8ANDITONE PREDOIIINANTL Y IlL TITONE PREDOIIINANTL Y MUDSTONE * DATUIIIS HIGH GAIIIIA IIARKER WITHIN THE "PER KALUBIIC FORIIA'I10N ~ (;) CD 0 ca CD ~ (') D) 3 D) :J D) ::J C. "tI !1 (þ ~ :x D) ~ c. ~ ñ. ~ ,<-,~ ..... 0 ~ ..... L) 1022 tJ 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 (Detter man et ai, 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 aI, 1980; Bushnell, 1981). The hydrocarbon reserves of the Kuparuk oil field occur within the Kuparuk Formation. The correlative sequence in the Mobil North Kuparuk 1 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 1 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 mèmber. 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 uReservoir 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 ina shallow marine environment. Miluveach Formation.- The stratigraphic sequence between 6,262 and 6,793 ft (1,909 and 2,070m) 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 (Detter man et ai, 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 .. ,.......' .. ... - .--. ~ !:.!.!.!..!!.!! - ...MGM-OUT/1I1UMCATION - Ol~-WATI!II-GOMTACT 0 A""AOX. ....A- DIICOYERY FIELD ~ WELL Aft!A 0 1 I I :t a 4 I I I Mil.. SOUTHWEST KUPARUK FIELD NORTHEAST 1.e 1.8 2.0 FIG. 9-Structure at top of Kuparuk reservoir is best defined by a strong seismic reflector at approximately 1.3 to 1.5 see two-way time on seismic line iDustrated. 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 piucb-out and nncadon to the west and south and along the line of an oil-water contact to the east and north. ~ ) '- 1024 Kuparuk Oil Field, Alaska type section, namely a dark gray brown, madne mudstone with numerous siltstone and silty mudstone horizons. Source rock studies, have suggested the total organic car- bon content of these rocks is about 30/0 by weight in the Prudhoe area (Seifert et aI, (979). Whereas the Kingak is as young as early Tithonian and Kimmeridgian age in northeastern Alaska (Detterman et al, 1975). the youngest Kingak determined to daie 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 see 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 SO to 100 ft (is 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 down flank 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 0.50 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 resuhed 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 in 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 0 unit are not considered to contain any res- ervoir zones. The A unit consists of a heterolithic sequence of sand- stones, siltstones, 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. The mud- stones within the A unit are dark gray-brown and silty. X-ray diffraction analysis of the sparse (less than 5070 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 clastics. 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 oftheCunit (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 '10 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 6OO¡o of the field's oil in place. WEST EAST WEST SAK 18 WEST SAK 11 WEST SAK 9 WEST SAK 12 WEST SAK 1 GR RI!8 6T GR Z DATUM * x:o ¡¡¡:: ;:)4( ..IS C/ 4( a:: ~o &&. C) CI I Z 0 I a: 0 ca i~ ... CI ¡::IE ~ f~ 04: ø'flot/l' :IE (") ¡ex: a:: II ... 'W 0 3 0.. 11. II 0.. ::> :2 UJ II Z :2 - 0 Q. t- "tJ CI -4"lJ,.".,. (1) - 0 CD a: Z ... iUJ :r: '= <l II LOCA TION MAP :E (1) a. w ,---J :Ii, ~ :e ¡ a:: õ' Legend ~:. W ;j ~ :~ ex: ~-" <C r-l PREDOMINANTLY 0 0.. """ L--.J .ANDSTONE ::> ~ [:~:?i .'DEAtTIC SANDSTONE 100 --.- l' :c z f-= ~ ::.~ PREDOMINANTLY C)O S,LTSTONE - .150 f..t ~ ~ ... > 4: . . ;:) :E ... - ~ PREDOMINANTLY VERTICAL SCALE * DATUM IS HIGH OAMMA MARKER ..... ... a:: MUDSTONE (NOT TO SCALE HORiZONTALLY) WITHIN THE UPPER KALUBlK FORMATION -0 ~ u.. FIG. 10- Lower member A unit and upper member C unit of Kuparuk Formation contain principal reservoir zones of Kuparuk field. Correlation of regressive depositional cycles within these units displays truncation in western part of field in lower member and onlap and overstep in upper member. ...A. 0 I\,) U'I 6.,) 1026 ) ,,/ Kuparuk Oil Field, Alaska The lithologies of the B unit arc 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 cm) for the sandstones and from 2 to 4 in. (5 to 10 cm) 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, the~e 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- genic 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 25070 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 wel1- 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. Intergranular clay is present in quantities of approxi- mately 3070 by volume in the reservoir sandstones and up to ISOJo in the finer grained clastics. 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 ft (46 m) on the eastern flank (Fig. 11). Jamieson et aI'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 IS well and was probably deposited coevally with part of the 0 unit (Fig. ..- ----- --~- ISOPACHS OF THE KUPARUK FORMATION 0 5 L ... " J MilES FIG. 11-lsopachs(in feet) of Kuparuk Formation and of four informal Kuparuk units show a common thickening trend toward the northeast. Lower memberA 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 mi2 (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 21070 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 40070 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 (l981). 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 0.6010) oils and are char- acterized by pristane to phytane ratios typically less than 1.5 and óBC and Ô34S 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 } @ -- \ ',::", ;4ì , + 0 / 4- ISOPACHS OF THE KUPARUK FM. A UNIT 0 5 I ..1 I I I , . MILES ~ .@ "~ 4- ,/::'~:<:',: "', , 0 - , ,~ Æ0Ð - H ~~!~,j;~i~;( " "~~:, . , , ,~ , ~' '" ",~, I _1~:~ ... -/ r. ,. "'6:" ,: ,,~ø<,;:.. 'ø-;' .,~, ",'.:-: , ,:"',' ., . ~ ~ > :,'i<' - ~;'::...;':~>' '.' , "" ',.:' ":-. " + , + 0 4- ISOPACHS OF THE KUPARUK FM. C UNIT 0 5 L~. t 1 , I j MILES 1027 "'ì ~-,- } -0 -t ~~ - + ~ " . :, ":".". 'íl '8. .'" ' :"':"',<_?'~!.~:',~~ ,: -'15 ";':~ :i" "f\i~ø-'.. +'~i: -?- .. .;,.,~. I. I, :~~..I ¡+- ISOPACHS OF THE KUPARUK FM. 8 UNIT ~ . . , . ~ MILlI I) <? -?- H "\J~ -- <,., ' \~o.. ~ : 0: ,> L/Í '~QO :, "'<,,~" ',.--'..,;~-~.. ,:,::,,',-~ \ -: ',,''''''':'~~- ~i¡~f:~~\/ ,:-':~. " :''I"'".,, -t -+ + ~ 0 ISOPACHS OF THE KUPARUK FM. D UNIT 0 5 1 I I I, I I FIG. I I-Continued MIUI 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 low naphthenic makeup, suggesting perhaps that some prefer- ential biodegradation has occurred. The sulfur content ranges from about 1.4 to 2.0070 by weight. The gravity of the Kuparuk crude ranges from about 15 to 26° API 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 600E 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 L) '-" 1028 Kuparuk Oil Field, Alaska -.- - ~--'-'-". - -.. -- . .-. ".-.----. ----- t- 800! LL. I I I I 'AVERAGE GRAVITY It, IS 248 API@60.Fr-'=-,II' 1 ..' [..1 ...~. fr . ..1.1 :' i ,t, /t , ' II I I 1. ¡:. .. i ~ 7001 0 Q I Š 8001 Q. :¡ 500. t- Z W 400i > 0 m c( 300. I- % " i:ii 200. :J: 100. 0':"" -... ,~.._.._,~,¡- 14 18 18 2'0 2~2 --"."2-4-"--2'8-28 CRUDE GRAVITY: 0 API FIG. 12-Plot of Kuparuk crude gravity versus sample height above oil-water contact demonstrates trend toward heavier oils (15 to 20° API) close to water level. Average gravity is 24° API at 60°F. western Prudhoe (Eileen) area has a similar API oii 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 11 to 26° API 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. Morgridge and Smith (1972) attributed the 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 buded 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-Albian HRZ unit. Jones and Speers (1975) reported that the dis- . J i tributioll of residual oil in cores from below the Prudhoe fidd oil-water level indicated that primary migration filled the structun~ to the spill point before the regional LateCre- taccous 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- ure 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 aI, 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 aI, ]980). TECTONIC SETTING The tectonic style of development of the north Alaskan continental margin is considered to be of the passive, Atlantic type (Grantz et ai, 1981), and along this margin are three distinct geologic and physiographic sectors (Grantz et aI, ] 979). From west to east, these are the Chuk- chi, the Barrow, and the Barter [sland 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 clastic sedimentation succeeded by argillaceous deposition during Jurassic time), the provenance was effectively removed by pull-apart 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 aI, 1979; Jon~s, 1980; Grantz and May, 1981). Within the Barrow sector, the Barrow arch is thought to be a partial remnant of the northern landmass which còntinued 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 (t 974) and Falvey and Mutter (1981). . . C' ~ George J. Carman and Peter Hardwick 1029 --KUPARUK FIELD' . WEST A ~,,¡q'A'" ~ PRUDHDE SAY FIELD EAST A A & " ~ ~' . ///J//////////I Colville Gp. /111, 'U R ž I Ú'nit I1I111111I11I1 ~ ~KUI - Fm. C) > MIGRATION PATH D OIL GAS A B C D E GAS CAP No No Small Cap In Yes Yes .v-~ API 17° to 26° 24° 21.9° 25.4° 25.10 ~ (Field average is 27°) ~ ð34 S -2.15 Øo4 -1.91 -2.57 -2.70 :2 Ó 13 C -< -30.2 UJ -30.32 -29.89 -29.83 ~ Pr/Ph < 1.5 <1.5 :::J 0.8 1.0 1.2 ø:= -- CPI < c. 1 c. 1.0-1.5 ~ 0.94 0.97 0.97 :::J Biodegrad. 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 at, 1979; Magoon and Claypool, 198t).1t is possible that (I) primary migrated hydrocarbons accumulated in Prudhoe structure (D and E) before Cretaceous and Tertiary tilting induced (2) secondary migration/overspilling into western (Eileen) portion of Prudhoe structure (C) and furtber migration (3 and 4) into overlying Kuparuk (B) and Upper Cretaceous (A) reser. voirs. Analyses from IocationsC, D, and E are Magoon and Oaypool's (1981) results from tbe wells N.W Eileen State I (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. "'or further analytical comparisons see Table IV in seifert et al (1979). . . C,') ...; 1030 Kuparuk Oil Field. Alaska CANADA BASIN BARROW ARCH PRUDHOE HIGH COLVILLE FOOTHILLS TROUGH ;:7 t\t.þ. ,o~~/ ,,/ ~...~ O~1 07\" ,os G~~ 6~O ,~o y ,/ ~ ~: 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 e"ploration 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 infrarift sediments (Fig. 14) 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 nonheastward 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 late Albian time. Such a thermal event may have contrib- uted to the maturation of source rocks in the Kuparuk- Prudhoe area. DEVELOPMENT PLAN The proposed development area of the Kuparuk field is approximately 200 me (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 bU. 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 potentia] of Naval Petroleum Reserve No.4 North Slope, Alaska: U.S. Geological Survey Open File Report 77-475,62 p. Clutterbuck, P. 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. 473-478. Denerman, R. L., H. N. Reiser, W. P. Brosgé, and J. 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 plate tectonics and the evolution of Australia's passive continental margins: Australia Bureau of Min- erai Resources Geology and Geophysics Journal, v. 6, p. J -29. 1031 (ìrantz, A., and C. E. Kirschner, 1976, Tectonic framework of petro lifer- ou~ rocks in AJaska, in Circum-Pacific Energy and Mineral Resources: AAPG Memoir 25, p. 291-307. -. - andS. D. May.1981,OriginoftheCanadabasinasinferredfrom seismic geology of offshore northern Alaska (abs.): Alaska GeoJogi- cal Society Mini-Symposium on The Origin of the ArcticOceen (Can- ada Basin). -,- S. Eittreim, and D. A. Dinter, 1979, Geology and tectonic devel- opmenl of the continental margin north of Alaska: Tectonophysics, 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. Mcintosh, 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, 1915, Permo-Triassic reservoirs ofPrud- 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., 1916, Tectonic framework of northern and central Alaska, ¡nCircum-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, cd., The future petroleum provinces of Canada-their geology and potential: Cana- dian Society of Petroleum Geologists Memoir I, p. 315-386. Magoon, I.. B., andG. E. Claypool, 1981, 1Wo oil types 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 Stratigraphic oil and gas fields-classification, exploration methods, and case histo- ries: AAPG Memoir 16, p. 489-501. Orth, D. J., 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. Rick wood, F. K., 1970, The Prudhoe Bay field, in Proceedings of the geo- Jogical seminar on the North Slope of Alaska: AAPG, Pacific Sec- tion. p. L-I to l-II. 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 orocline, 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. IS. p. 146. Tourtelot, H. A" 1979, Black shale-its deposition and diagenesis: aays and Clay Minerals, v. 27, p. 313-321. Vail, P. R., R. M. Mitchum, Jr., aDdS. Thompson, 1977, Global cycles of sea level changes: AAPG Memoir 26, p. 83-97. =+t: \0 ::t:t: 00 ) ) . ÆUJD}O.- P (f[rf f IH 0 Ov -e;r $ ¡ Jfd [)c ~s p {CLG¿P A cz6rnpcuv-~~ t -h¿ Î I <~f )0) U---tb.JL) J(i )C}Céffec{ Lh o.1~~ ~~ COYL!1è1-í:11.r/'o.-Q- ¡20(>'hJ yYlap ¡(ack.- oj-ap jf~ ~r--ej~V CçJJlfd£j~h~V ~.ruut C~ S .Dó\;vUo ) ~ . () BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 5645111 l bp RECEIVED July 31, 2001 JUl 31 2001 Commissioners Alaska Oil & Gas Cons. Commission Al k 0.1 d G C . C .. Anchorage as a 1 an as onservatton ommlSSlon 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 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 1-3 and 1-9 have been amended. . Three exhibits 1-2, 1-5 and 1-6 have been provided in a large format. , . Exhibit VI-l 0 is a NOPF map of the Aurora and Borealis structures. Aurora is a contiguous pool separated from Borealis. . Exhibit VI-II 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 RFf 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-l 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. L) BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 5645111 L) bp 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 Position Ops. Eng. Dev. Geologist Facility Eng. Geophysicist Res. Eng Office 564-5754 564-5972 564-4350 564-5103 564-5173 cc: Randy Frazier (BP) J. P. Johnson (PAl) M. P. Evans (ExxonMobil) P. White (Forest Oil) (.. EXHIBIT 1-3 Amended L) AURORA PARTICIPATING AREA (APA) ADL 28254 18 17 r--,-- I ADL 282551 I ~ I I I 19 20 I I 21 I Expansion I Exp I Area 4 I Area 3 , I , 29 ~ '--r ADL 28259 I IE . xpanslon I Area 2 ~ ~ I . 16 30 r ADL 47450 ADL 28253 15 ADL 28256 22 28 27 APA ADL 28258 34 4 3 ADL 28261 I ADL 385193 ADL 47448 PBU Boundary 23 26 25 - -I ADL 28257 I . Expansion T12N-R12E - I Area 1 I 35 . 36 n r _I I , T11 N-R12E 2 1 ADL 28260 Exhibit 1-9 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-3l Sidewall core (S-103 RST) ---. S-24Ai RFf -J 6835' tvdss 6824' tvdss Per North of Crest Per North of Crest 6812' tvdss owe (Beechey Pt St #2) (V-200) Block Block (N Kup 26-12-12) ,,~, v Exhibit VI-II: Aurora C4/C3B and Borealis C4A/C3B NOPF Map and Lease Ownerships 91.19 08.81 BPX 91.19 AMOCO 8.81 BPX 91.19 BPX 91~19 AMOCO 8.81 AMOCO 8.81 BPX 75.00 AVCG 83.33 BP AVCG 25.00 BPX 16.67 75. AVe 25. 01-3' ~9-01 01-29-01 01-29-01 01-29-01 01-31-03 07-31-01 A[ 25906 ADL025518 ADL028231 ADL028232 4 ADL385201 ADL377051 385: BPX 91.19 BPX 91.19 BPX 91.19 BPX 91.19 BPX 50.00 BPX 50.00 BPX 66.67 ~HEVRON 50"' AMOCO 8.81 AMOCO 8.81 AMOCO 8.81 AMOCO 8.81 PHILAK 25.00 PHILAK 25.00 PHILAK 33.33 MOBIL 50.00 =><XMOB 25.0C EXXMOB 25.00 .) 01-31-03 01-31-03 03-31-01 03-31-01 09~0-02 09-~0-02 01-31-03 09-30-79 . Aßl3301õ!} ~U07 AJJt37,5ffl3, ~nI3~1.3~. 1\DLC:?1J?5~ 7--\D~8253 ADL3~193 J..DL0474¡ %SAMEr- CHEVRù 5O.oc'CHEVRCN 50.00 '/%~6n~L_j - I ~¡ ... MOBll~K 66.67 I ~ - - MOBILJ 18.25 MOBILAK 18.25 PHIU\K 50.00~ c. ~IL, ,r""'1~SAME PHilLIPS 3333 ' EXXMO 17.91 EXXMC.? 17.91 EXXM03 50.00 . - - , ;' P-iILLlPS 50.0 - BPX' .33 BPX '13.33 .Expan.lo~ 09-30-02 PBU Boun~ary M':>BIL AK 50.C - ~ --'J6SAME' -'-M?8~'êA ö~~- ---M¡?8A~, ~Kõ~or--' --..-..__.__m______-.--.-.---"- , ,~ 4___-w~. i. ¡ I.l %SA,' ME %SAME O~ -:"7-84 \, 10-" -79 09-3J-79 , e9-~' ,- \ 9 f 09~0-79 A 09-30-79 ADl ::25637- \AØOÐ 7446 ADlq47447 A ~!-8a6'.~~3, lq2~256 - APL047448 - ÅDL04746~ PHILÁK 55.29 ~AME' , I ~ / :~,D ILAK 36.49 PHILA< 36.491~RlLAK, 36.49 PHILAt< , 36.49 PHlLAK 36.M: u~~~r9'~~5 SOCN..8S-"NY__~ -~ %sAME ' ~~,p~6~82 ~~~ê'82 ~~,p~J:i82 ~~,p k~1i82 ~~,pB26~si8 MOBn.-~_--.ri~ ' .------.------.-- --- ,------_..__.~-_._-_...._._--_.__.~pl!9\~~~t~~~~.tf~, ~':~~ 0 1~0 M~~~tlK Þ~.~J3~~~K 01~ CHEf 0 11 ~ \ nL1-08I . - Expan.lon !. Ex¡faMlb: T12. : œ.i7-84. I 09-,0-79 '03-27~- 03- - 09~0-7! Area2 ~ 09~0-7~ ~~b8-~1-7,...; 03-27-84 ADLQ25638 ; ADL~i449 W!ö°282~ ADLO: 823t.. ADL0282Ì59 ~'DLO~8258 ADLQ28~7 ÄDL02827! PHIIAK 55.29 -EXXMQÐ ~~!LA < 36.~ PHILAK 36.4"1 CHEVRC;N æ.33"~IL.AJt 36.49 U¡;;'ilÄK;;"s.r.JIIJ PHllAK 36.4i BPX 39.28 PtfJLAK ~6:ðlf I:.MMCB 35.82 EXXM~ 35.,.2 PHILAK 24.33 E>eEMO, 35'2 EXXMO~ 35.82 EXXMOB 35.E UNOC~L 4.95' ~1f,.51 M~r! 1.0 cr~~~R6.'K ~~,p~7~å88 1\J3~~ÄRtI.~.oo MJ3~~ÁR6.6f.OO f\lJ3~~AR6.sr. MOS ...O......0.36~-UNOCAL- ,-4.95 m"-FORe::---'-Ð:G2--"-''''- - 6--::--.--t}.Ð..!--- MODIlII\K----Ø:&1- - FOReE 00,2- roRC~.02- =ORCE 0.0: CH 0.11 OTHE~S 0.47 ,OTHERS 0.01 - - ¡ ! 03=2 ¡ 03-27-8 03-~ C3-?j -84 09-30-79 - 03-2T -84 03-?7-84 03-27-84 ABLJ~5649 . '., '242 '- "ADLO~8~ j\ "'I ~J z~ø lO474GO - ~L020261 ADL028260 \DL02828: PHIUtt( 55.29 ,~ PHI ~ 55;29 "" .. _.,,,,,.8~ ~?OO.OO %SAME" CHEVRON 33.33, PHILAK 36.4 !3~ 39.28 PX! _~.28 %SAME %SAME %SAM&s. *7 -aso- - m~'à ~~ ~~,p~6~~ . UI'IVChL UNOC, ~.95 z-oe. 82 2-1 AD~~èr63-1 BPX 17.78 MOBILAK 1. I MOBI ..._..o..36~MOBJL.. -.-..0.36 --.------.--.--.. --.--.---.------.. "- I~}oo .-;s~-' MOBIL AK 0.67 FORCE 0.0 C - 0.11 CHEV. 0.11 %SAME z-oe. ~ %SAME ~ FORCE 0.01 O~-~ B4 03-27-84 03-~7-84 \ 03-27-84 03-27-81r8l'Q. - 09-30-79 03-27-84 ADL025 50 . ADLC28243 ADLC 28244 ADLO !824~ Z-03o 02:~~-2 ,- AD~lé~-2 ADlO47451 ADl0282€ . PH1tÀK J 0 '.2~%SA\}1: 1- 'I 'Ht'X ..OO~O I ., I I I IcfTfVOON' aa:a3 CMiVAON 33.33 PHILAK 36.49 PHILAK 36.l BPX 39 28 ' PHILAK 24.33 PHILAK 24.33 EXXMOB 35.82 EXXMOB, 35. UNOCAL .4 95 \ EXXMOB 23.88 EXXMOB 23.88 BPX 26.66 BPX 26.66 , MOBIL 0 036 ADL028248, BPX 17.78 BPX 17.78 MOBILAK 1.00 MOBILAK 1 CHEV.. 0.11 J3-27-84' %SAME ~~ :.~~ M~8J}JK 0~Ó~7 M~8Jtc~K 0?Ó~7 FORCE 0.02 FORCE O.C 03-27-84 01-31-03~ 01-31-03 03-27-84 ' 09-30-79 09-30-79 03-27-84 03-27-84 ADL0256~~ - ' .... . U 3~1_\ !,~~~~~~8.: ~~~~~~~4.._: AD~0474?3 AD L047452 ADL028264 AD L0282E - -'-'" II n"1I ^&l ~AAQ PI-IU AK 3R.¡ ~ /""........." U .J "......, u Exhibit VI-12: Aurora RFT Pressures Aurora RFT Pressure Data 6300 . .S-104 C-Sand 6~OO ------------------------------------------------------------------------------. ----- )Ie V -200 C-Sand . S-24Ai C-Sand 6E)OO --------------------------------------~---------------------------------------- ----- S-24Ai A-Sand 6600 - - - - - - - - - - - - - - - - - - - - - - - - - - ,- -, - .- - - - - - - - - - - - - - - - - - - - - - - - - - - -, - - - - - - - - - - - - - - - - - - - - - - - - ,- - - - - - - - - - - ,- - - - - ... - - - ø ' , ~ ':::::::: ~~-~~~~---~~-~-~~~-~~~~--~~~-~~--~~~~-~~~~~-~~--~~--~~~~-~~~~~~--~~--~~--~~~--~--~~ 6900 -.. - - - - - - - - ~~ ~ :_~i - ~~~~ n~ - ~ r~s~..~ ~~~- - - - - - - - - - - - - - - - .. - - - - - - - - ~.. - - - ~ - - - - - - - - - - - - - -- - - - - - - )t( 7000 - - - - - - - -- - - - -- - - -" - n -.. - - -.. - -.. .. .. - - .. -- -.. - - -- - - -.. - n - .. - -.. u" - -.. -- n --...... -- --u - - - - .... -- .. - - - .. .. .. --)I( - - .... - .. --.. 7100 3150 3200 3250 3300 3350 3400 3450 3500 3550 3600 psia <-) L) Exhibit VII -1: 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. ll. 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. b. 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 ( I. 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. ::t:t:: '-.) t AOGCC 1~NSCRlPT OF PROCEEDINGS } ) July 24, 2001 t ) 1 2 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING Page 1 I I I 3 In Re: 4 5 AURORA OIL POOL, PRUDHOE BAY FIELD POOL RULES AND AREA INJECTION ORDER. 6 7 8 TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska July 24, 2001 9:00 o'clock a.m. 9 10 APPEARANCES: 11 ) Commissioners: MS. CAMMY OECHSLI TAYLOR, CHAIRPERSON MS. JULIE HEUSSER 12 * * * * * * 13 14 15 16 17 I 18 19 20 I 21 I 22 i 23 i 24 15 i ~ ;¡' , -~ METRO COURT REPORTING, INe. Phone (907) 276-3876 745 West 4th Avenue, Suite 425 metto@gci.net .) AOGCC ~RANSCRIPT OF PROCEEDINGS ! ) 1 PROCEEDINGS 2 (On record - 9:06 a.m.) 3 THE CHAIRPERSON: I would like to call this 4 hearing to order. Today is July 24, 2001. We're at the AOGCC 5 offices at 333 West Seventh, Suite 100. The time is 6 approximately six minutes after 9:00. The subject of today's 7 hearing is BP's application for pool rules and area injection 8 order for the Aurora Oil Pool. At the head table here to my 9 left is Commissioner July Heusser. My name is Cammy Taylor. 10 And to my right is Laura Ferro from Metro Court Reporting. 11 These proceedings are being recorded and transcribed. 12 Transcripts can be acquired directly through Metro Court 13 Reporting. 14 Today's hearing was noticed for a public hearing and 15 published in the Anchorage Daily News on June 22, 2001. The 16 order of proceedings today, the Applicant will present 17 testimony first. All persons wishing to testify will be 18 sworn. If you wish to give expert testimony, we will ask that 19 you provide your qualifications and the Commission will decide 20 if your testimony will be accepted. Each -- any member of the 21 audience who may have questions that they wish to have asked 22 can submit those in writing through a Commission 23 representative. Mr. Crandall is seated in the back of the 24 room. He can forward your questions to the front, and if 25 there are any persons wishing to make oral statements, they Page 2 Page 3 1 2 3 4 5 6 7 8 9 1 0 first? 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) 1"'''''-'''---'''''~~''~:.o1III<Ij:~''''' ~"~.ffKo't~~.~~~t~,,~~,m'-, '",\~"""'11"" ~-"''''.)f'O' 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 MR. POSPISIL: I'm just going to introduce the proceeding. 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? July 24, 2001 Page 4 1 (Oath administered) 2 MR. CERVENY: I do. 3 PHILIP FRANK CERVENY 4 having been first duly sworn under Oath, testified as follows 5 on examination: 6 DIRECT EXAMINATION 7 THE CHAIRPERSON: Would you please state your 8 full name and who you are representing, and spell your last 9 name so that the recorder has it on record. 10 A My name is Philip Frank Cerveny. I'm representing BP 11 Exploration Alaska. 12 THE CHAIRPERSON: How do you spell your last 13 name? 14 A C-e-r-v- as in Victor, e-n-y. 15 THE CHAIRPERSON: Thank you. Do you wish to 16 be considered an expert? 17 A Yes, I do. 18 THE CHAIRPERSON: Would you please state your 19 qualifications? 20 A I'm a senior development geologist with BP Exploration 21 Alaska. I've received a bachelor of arts and master 22 of science degree in geology from Dartmouth College, a 23 doctor of philosophy degree from the University of 24 Wyoming in geology. I was employed by ARCO 25 Exploration Production Technology starting in 1990 and Page 5 1 have worked on a variety of projects in Alaska since 2 1991. I've been working with the greater Prudhoe Bay 3 Western Development Team since August of 2000. I 4 would like to be acknowledged today as an expert 5 witness. 6 THE CHAIRPERSON: Okay. Do you have any 7 questions or anything? 8 COMMISSIONER HEUSSER: I have no questions. 9 THE CHAIRPERSON: We'll consider you an expert 10 witness. 11 A I'll begin with the geologic introduction. Thank you. 12 The Aurora Pool is located on Alaska's North Slope as 13 illustrated Exhibit 1-1. This is a map showing the 14 North Slope, the unitized areas of the North Slope and 15 the Aurora Pool shown by the circle here. Adjacent 16 are the Kuparuk River units, the Prudhoe Bay units, or 17 the North Star unit, and the Milne Point unit. North 18 is -- north is to the top of the map, and note the 19 scale here down to the lower right. 20 The Aurora Pool was confirmed in 1999 by the 21 drilling of the V-200 well. The reservoir intervals 22 for the Aurora Pool is the Kuparuk River Formation. 23 The Aurora Pool overlies the Prudhoe Bay Unit, PBU, 24 Saddlerochik (ph) Group reservoirs in the vicinity of 25 S-Pad. In addition to the V-200 well, the S-100, the i t ~ ~ ¡ ¡r: ¡ ¡" ~ ~ '---,,~m.~.. -_hm'_~-~:]r-'-' -'----'1."'wn...""",""" -iIt"~'~J"" t~>'''''''':.:.r.,~~~'"",~.r,u'''~~-'''''''"''''''''~'''~'-''''U''''''''''-':~~J''''<'''W,........~""..",w".......",~\.",.,..........-,,,,,.l.. 2 (Pages 2 to 5) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ÓI AOGCC TMNSCRIPT OF PROCEEDINGS I ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 6 8-101, the 8-102, 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 1-2, 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 Page 7 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 July 24,2001 and the measured depth as drilled in the well, Page 8 J 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 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) ,>(,,...~_.........~--.,,,. '~'n'--",,,,,,),~,,,;,:-><;ifo.~~"'''''-''''- -~:~~W)1"'''' y¡n.... n.'. ~m--",~nij(li1Jf-\'~~'\ ~~_._.._---._..._..__m,--_<.<~ - ""-'~'r.--J"''''''''''''W~~\ib~~~~~~><.r",>.i'i''''\.'''''''''''';:~¥ "'0.."'" .. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 9 stratigraphically complex characterized by multiple unconformities, changes in thickness and sedimentary faces, and local diogenetic cementation. As shown on type log in Exhibit 1-4, 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 Band 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 right at this spot. Exhibit 1-3 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 1-4 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, ~~~»'~4;-,"-,,¡o..,:'~:o;:';~":"""~-""_I-='- ----- -.--.".6 3 (Pages 6 to 9) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ) AOGCC T..,RANSCRIPT OF PROCEEDINGS I ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 '23 24 25 Page 1 0 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 Page 11 July 24, 2001 Page 12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 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 Page 13 1 1 laterally and vertically. 1 interval and is considered non-reservoir. In the 2 The lower Kuparuk A interval contains two 2 western portion of the Aurora Pool is dominated by 3 reservoir quality sub-intervals, the A4 and A5 3 silty mudstone with occasional very fine grain sand 4 intervals shown here, which are 30 feet and 20 feet 4 laminations and inner beds. In the eastern part of 5 thick respectively. In the V-200 well, these sands 5 the Aurora, the C2 lithology transitions to very fine 6 are wet. In structural higher portions to the east, 6 grained muddy silty sandstone indicating a lateral 7 these A sand units are expected to be oil-bearing and 7 faces change from west to east. The C2 interval has a 8 productive. The A5 sand appears to be higher quality 8 somewhat uniform thickness of 28 feet to 36 feet in 9 reservoir than the A4 sand. The overlying Kuparuk b 9 the western part of the field. The C2 thins to the 10 interval is dominated by siltstone and sandy mudstone 10 southeast and is evenly -- is eventually truncated. 11 with numerous discontinuous thin sandstone lenses, the 11 The C3A sub-interval is composed of coarsening 12 thickest of which are up to three feet thick. In the 12 upward sandstone beds inner bedded with silty 13 V-200 well, wire line logs show these thin B interval 13 mudstone. The sandstone beds range from one to two 14 sands to be wet. 14 feet thick, silty very fine grain sand at the base, up 15 The uppermost unit, the Kuparuk C interval, 15 to 10 feet thick fine grain sand at the top. Mudstone 16 contains the primary reservoir sands of the Aurora 16 inner beds display lateral faces variations similar to 17 Pool. The thickness of this interval is variable and 17 the underlying C2 sub-interval, and that they coarsen 18 ranges from zero feet at the eastern truncation to 210 18 eastward to silty very fine grain sandstone toward the 19 feet at the Beechey Point wells in the northwestern 19 truncation. The overlying C38 sub-interval is 20 portion of the Aurora Pool. The lithology of this 20 distinguished from the underlying C3A sub-interval. 21 upper unit is variable consisting of interbedded very 21 Sandstones amalgamate in the mudstone inner beds are 22 fine grain to medium grain sandstone with minor 22 not present. 23 amounts of muddy siltstone and sandy silty mudstone. 23 The C4A subinterval continues the coarsening 24 The Kuparuk C sands are generally very quartz-rich and 24 upward trend from fine grain sandstone at the base to 25 moderately sorted. The Kuparuk C interval is 25 medium grain sandstone toward the top. Due to ,~"',.-~"., -~~~"... - ~-' ". .... ' _<"'''%%h'm-'' ..'. """"","""'-""~' "'-,..'..-....,_..'.....'..- ........"'-.-'-""-"'.-, "'."'=C'''''_'1>~-,._~~-........_~.ft,....,._,...........-~...- t 4 (Pages 10 to 13) Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC 'kRANSCRIPT OF PROCEEDINGS ! ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) Page 14 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 1-2 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 Page 15 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) "-"'''''~~ ."""'~1:"''''.';''''-Ìt~~:'''"", ~""""'''''~'.'''~'.L'i)'i~~),¥'-~''''''.~~'\'~'''''''' "\'11'''''' ~~.....,~ 'I'f""''''t:~~'. "'''''-.''-'''',V''' -..~- ._~"(._""" .'~ti".a~~m.....,._..~ - 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 into an eastern half, which is the fault mentioned here, eastern half which contains the 5-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 1-5, Aurora can be divided 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 July 24,2001 Page 16 ~ 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, 5- 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 5-103,5-104, 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 i Page 17 and truncation of the Kuparuk Reservoir. Eight S-Pads Sag Ivishak wells penetrate the Kuparuk Formation in this block. Exhibit 1-6 is a northwest to 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 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 1-7 is a dip oriented seismic traverse at the same northwest to southeast location as the previous cross section. Again, see Exhibit 1-2 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 ~ "''('''''~1~W''''''''''''''''''''''UY' ,'..n ,,,-,,,"W '\f""~ --"r-""""'.'''''''' u ''''~'... U~ "" """""':W!i'Ø''''''' ......... ~"""""ifi...m'7< ...._._.~_..''{'''''----~.._~.. '---. ; 5 (Pages 14 to 17) Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC TAANSCRIPT OF PROCEEDINGS I ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 ,17 18 19 20 21 22 23 24 25 ) Page 18 these formations are -- are faults. Exhibit 1-8 is a strike oriented seismic traverse from southwest to northeast. Again, see Exhibit 1-2 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 1-9 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 ) July 24,2001 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 C4, and lower cretaceous unconformities. These Page 20 I 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 C3S 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 Seechey 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 I Page 19 1 compartmentalization of the Aurora fault blocks and a 1 generally the order of 10 to - 10 to -- 10 or less -- 2 westward deepening of the OWC across the Aurora area. 2 20 or less feet through the heart of the Aurora Field. 3 At present, a common GOC, or gas-oil contact for the 3 Exhibit 1-13 is a net hydrocarbon pore foot 4 Aurora Pool has not been identified. Based on wire 4 map of the Aurora Pool with a contour interval. It 5 line logs, core analysis saturations, and core 5 says in the document ten feet. The contour interval 6 staining, a GOC is interpreted in the S-16 well at 6 here is actually one foot. This map is - basically, 7 6,631 feet tvd subsea. Based on well tests, mud log 7 they took all the rock away. This is the oil that 8 and wire line logs, a GOC is interpreted in the 8 would be left. This is how much oil, total oil 9 Beechey Point State number 1 well at 6,678 feet tvd 9 accumulation there is in the Aurora Pool. You can see 10 subsea. Sidewall core saturations and staining and 10 the one foot contour around bounding the limits of the 11 RFT pressure gradient data and fluid samples from the 11 Aurora Pool. This concludes my testimony. 12 S31 and S24A wells and the Crest Block indicate oil 12 THE CHAIRPERSON: Thank you. Do you have any 13 above the GOC depths in the S16 and Beechey Point 13 questions? 14 State number 1 wells. The Crest Block appears to be 14 COMMISSIONER HEUSSER: Yes, I do. 15 gas-free. 15 BY COMMISSIONER HEUSSER: 16 Pool limits. The trap for oil and gas in the 16 Q Just starting off with a general question, will you be 17 Aurora Pool is created by a combination of structural 17 providing readable scales of Exhibits 1-2, 1-5, and 1- 18 and stratigraphic features. The accumulation is 18 6? 19 bounded to the west by several faults where the 19 A Yes. E 20 reservoir is juxtaposed against impermeable shales of 20 Q Full scale or reasonable scale? L 21 the overlying Kaluvik Formation and HRZ shale. To the 21 MR. POSPISIL: I'd say as far as the size of ~ 22 southwest and the north, the pool limit is defined by 22 those exhibits? ~ 23 the down dip inner section of the top of the reservoir 23 UNIDENTIFIED MALE SPEAKER: (indiscernible- 24 with the oil-water contact. To the east and 24 away from microphone) f ) southeast, the reservoir is truncated by the preaptian 25 MR. BAKUN: Right now all we have is the small t ;';"'~~..~...x~Q¡'(¡9' -"""'~~"'---"'-'\'1:i~»"S'1'*""'~.~'NV-'"''''t''''I(''' me.' ,~,,,::~~,,,,",,6:I.''''''''{'~~~~~~~~1\'\-.w-'~''''-'''N''''''''ff''II:'¡(.~~'~'' ROO' ~'~~}...,u,~;..~"~~....,;o.:~",~~,,,,~,,,:~*:~;,,,,",,:.,;:,.:>o:.;:¡"'m'I""~'" ,~"'i~fi{ ...-..ft';:"1'11.,"~"'-" '''''"~'.....................--_......."'.:..... ."'Ut_m...'."v."..,."....~ Page 21 6 (Pages 18 to 21) Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net . AOGCC '{RANSCRIPT OF PROCEEDINGS I ) 1 2 3 4 5 6 7 8 A 9 10 11 Q 12 A 13 14 15 16 17 Q 18 19 A 20 Q 21 A 22 Q 23 24 25 A 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Q 19 20 21 22 23 24 25 Page 22 collusion. Q Okay. Mr. Cerveny? A Cerveny. Q 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 -- 1-5, could you go over again what criteria was used to define these I blocks? So that would be the -- largely on the -- on the Page 23 fault, faulting, potentially compartmentalized areas, we have the Kuparuk Formationis -- 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. 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? ~}-, """,,......,,...,,,,,,.,,,,,,,,,-y~_._~.,,-,.,,,,,,,",,,,,,-,,,"=---,.- --., July 24, 2001 Page 24 1 A There shouldn't be oil above the gas-oil contact. I 2 don't think I mentioned that. 3 MR. BAKUN: (indiscernible) crest of the block 4 of the GOC and the Beechey Block so it's a shallow 5 (indiscernible). 6 Q Okay. You mentioned that -- when you were talking 7 about fluid contacts, you suggested that either there 8 was a range of uncertainty of the fluid contact data, 9 or there was compartmentalization of the various fault 10 blocks. How do you go about - excuse me, what are 11 your plans to determine what the oil-water contact is 12 versus just labeling it as compartmentalized? 13 A The oil-water contacts are largely -- I'd say future 14 plans would be evaluate wells on a well by well basis. 15 We've kind of taken a defensive position that these 16 blocks are compartmentalized and would probably 17 largely have varying well water contacts. That will 18 really only be proven out by further drilling for the 19 most part. We've calculated free water levels which 20 is the level at which there's 100 percent water in 21 most of the wells, and there's significant variation 22 in the free water levels across the Aurora Field, and 23 that's -- that's telling us that there's a good chance 24 that got some variation in oil-water contacts. Hard 25 oil-water contacts are very difficult to pinpoint in Page 25 the Kuparuk Formation. Very often they occur in the B unit, which is very shaJely, 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. 15 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: Thank you. (Witness excused) THE CHAIRPERSON: Would you like to raise your right hand? (Oath administered) MR. BAKUN: Yes. FREDERICK E. BAKUN having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION 1 2 3 4 5 6 Q 7 8 9 10 11 A 12 13 14 15 16 17 18 19 20 21 22 23 24 25 t ~~~~,v',&",.....~'tn\þ~:-,.y~~~~Md:.~~".t::::.nlõ 7 (Pages 22 to 25) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ) AOGCC 1:RANSCRIPT OF PROCEEDINGS J1 Page 26 ,) 1 THE CHAIRPERSON: Do you wish to be - provide 2 expert testimony for today's hearing? 3 A Yes, I do. 4 THE CHAIRPERSON: Would please state your name 5 for the record, spell your last name, and then provide us with 6 your qualifications? 7 A Yes. My name is Frederick E. Bakun. My last name is 8 spelled B as in boy, -a-k-u-n as in Nancy. I am an 9 engineer with BP Exploration Alaska, Incorporated, 10 currently working as the reservoir engineer for the 11 Aurora development project. I received a bachelor of 12 science degree in chemical engineering from the 13 University of Arizona. I joined BP in January of 14 1996, and have worked in Alaska on a variety of 15 projects since 1997. I've been working with the 16 greater Prudhoe Bay western developments team since 17 August of 2000. I would like to be acknowledged tOday 18 as an expert witness. 19 COMMISSIONER HEUSSER: An expert witness in 20 what area? 21 A In reservoir engineering. 22 COMMISSIONER HEUSSER: Reservoir engineering. 23 THE CHAIRPERSON: And has your work since '96 24 been in the area of reservoir engineering? 25 A Yes. Page 27 THE CHAIRPERSON: Okay. 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. 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 1 2 A 3 4 5 6 7 8 9 10 11 12 13 A 14 15 16 17 18 19 20 21 22 23 24 25 ) --'--_Y'G<o<->~~~""""",-,,~,~". .._~,_... ~,--",...~-'-'lJIt.......... W"" '''''''iI July 24, 2001 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 281 Kuparuk River Unit, KRU. Wells with Aurora core intervals in the data set are Beechey Point State number 1, S4, and S 16. 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, kvover kh, was 0.006 per 20 foot interval based on the harmonic average of routine core data. Typical single plug kv 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, Page 29 1 volume clay less than 28 percent, and volume 2 glauconite less than 40 percent. If the volume of 3 siderite exceeded 30 percent, the net pay was 4 discounted by a factor of 0.5. Exhibit 11-1 shows 5 gross thickness by zone based on marker picks, and net 6 pay based on the log model criteria. The 15 percent 7 porosity cutoff corresponds to approximately one 8 millidarcy of permeability and what could be 9 reasonably expected to be a reservoir. 10 Exhibit 11-6 shows a cross block of porosity 11 versus permeability. And this label - this exhibit 12 is labeled confidential. If there's anyone not 13 associated with the owners or..... 14 THE CHAIRPERSON: You may -- well, we may want 15 to hold on a second because right now we're on a public record 16 so everything that you are testifying to right now is in - 17 will be recorded and available to the public so if we want to 18 move into a confidential session, then we'll need to consider 19 that application. If you wish to do it, say, at a later..... 20 MR. POSPISIL: Would you like to see the 21 exhibit, or can you accept it? It's a power transform to 22 porosity. 23 THE CHAIRPERSON: This document was filed 24 under seal before with the Commission? Or was this the first 25 time? In the original application, was that document ! 8 (Pages 26 to 29) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC TRANSCRIPT OF PROCEEDINGS I ) 1 2 3 4 A 5 6 A 7 8 9 10 A 11 12 13 14 15 16 17 A 18 19 20 21 22 23 A 24 25 Page 30 provided? A This was not in the original. THE CHAIRPERSON: In the original, okay. Actually, this was in the June 15th submission. THE CHAIRPERSON: It was? This document was, yes. THE CHAIRPERSON: Are there any other exhibits that you are requesting be kept confidential? MR. POSPISIL: Confidential exhibits. 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. 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: .....50 far? That's correct. THE CHAIRPERSON: And the basis for the request that it be maintained confidential? Is this Page 31 ) July 24, 2001 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 32 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 11-1. 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 ~ I, r I 1 2 3 A 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 A 22 23 24 25 ) / ~ ~~~~"''''''F'f'''&'''''fN~'' -'~"~1""''''..rr'''''W'mJJ'if~''''''''''''~''''~ . ""¥A1f'U~' ~'~"'''-::"''''''1t'f'",~..,.'''.._.~.m'..n'_''''I~~~t'......~~~Wíti'~~;:..\..:.q.,:~W'.W)tw»'-.:~')m,~~~......,"-'-'~".........,'W-"-<.r.A.''''~~'II!'' n'~'¡' 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 33 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 11-2 shows a summary of fluid properties for the Aurora accumulation. This exhibit provides a fundamental reservoir ~ I , proprietary? MR. POSPISIL: Proprietary information. Proprietary, yeah. THE CHAIRPERSON: I'm sorry, what was the number of that exhibit again? 11-6? A 11-6. 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. (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 '''M.::' >,'MII. ~ ,.,., .,,,y.m__:"""-.._'1(_..n-..,,,,"" ..-- ,." 9 (Pages 30 to 33) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC 'tRANSCRIPT OF PROCEEDINGS r ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) Page 34 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 11-3 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 Page 35 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) July 24, 2001 Page 36 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 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) ,~ ~io1"'-""'.'~~'L.....~~,v~~~~-",-.Ñ.~"''*'';~'''''''''''~''.''''--''<¡'~--''''''_W--_..w"'&<~'''''~IA "''i("':r_'''''''~''_::';:¡~Ao'..''~-~~'i_''kr¥''" """§:'~':~-i'\"4f-' .m~~ 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 37 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-101 was drilled as a horizontal well in the southem portion of the V-200 fault block as the 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 GOe 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 10 (Pages 34 to 37) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC 1:RANSCRlPT OF PROCEEDINGS J Page 38 ) 1 second well of phase I development drilling. Log 2 analysis indicates the well has over 2,500 feet of net 3 pay. A December 2000 production test produced 1,062 4 barrels of oil per day at GOR of 20,707 standard cubic 5 feet per stock tank barrel. Well logs suggest the 6 possible GOC in the toe of the well at approximately 7 6,680 feet tvd subsea. Initial API gravity was 47 8 degrees. The elevated API was due to the production 9 of gas and condensate liquids. 10 S-102was drilled as a horizontal well in the 11 northern portion of the V-200 fault block as the third 12 well of the phase I development drilling. Log 13 analysis indicate that the well is approximately 400 14 feet of net pay, and that the reservoir is of 15 considerably lower quality than that for the S-100 and 16 S-101 wells. A December 2000 test produced 458 17 barrels of oil per day at a GOR of 1,205 standard 18 cubic feet per stock tank barrel. Initial API gravity 19 was 26 degrees. 20 THE CHAIRPERSON: Mr. Bakun, excuse me just a 21 second. If all of the material that you are reading from is 22 included in this packet, if Ms. Heusser doesn't have an 23 objection, I was going to suggest perhaps if you would like 24 since you've been sworn, if you would like to adopt this 25 portion as your testimony, if you would like to tell us what I \. Page 39 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: Page 10 through 18. That's correct. THE CHAIRPERSON: 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. 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 1 2 3 4 5 6 7 8 9 10 11 12 13 A 14 15 16 17 18 19 A 20 21 22 23 you. 24 A 25 ) ~-~~ ~,~-"~,,,.,t,_''''~:'ìlllr''i'~'..r.:~-*''~ ~""'~~---xï:JfI'''n And this comes under the model results looking at a comparison of primary recovery versus water flood July 24, 2001 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 40 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 11-5, 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 Page 41 1 development. 2 And that concludes my testimony on the 3 reservoir description section. 4 THE CHAIRPERSON: Okay. Ms. Heusser, do you 5 have some questions? 6 .COMMISSIONER HEUSSER: Yes, I do. 7 A And from here, we do have the confidential section. 8 If we'd like to move there, that may help answer some 9 of the questions that were brought up in the geology 10 section, or should we take questions. 11 THE CHAIRPERSON: And were you planning on 12 presenting that testimony? 13 A Yes, I was. 14 THE CHAIRPERSON: Do you want to wait and do 15 that first? 16 BY COMMISSIONER HEUSSER: 17 Q My questions are -- my current questions are primarily 18 around just what you've presented so far. 19 A Okay. 20 Q You've just demonstrated that there's a significant 21 benefit associated with a water flood at this 22 reservoir. When do you anticipating evaluating 23 miscible injection? 24 A We have performed initial screenings on miscible 25 injectant. Early studies indicate an incremental I t t ¡;; ~ ~ . ~ þ t L -'" 11 (Pages 38 to 41) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ) AOGCC TRANSCRIPT OF PROCEEDINGS I )1 2 3 4 5 Q 6 7 A 8 Q 9 10 11 12 13 14 A 15 Q 16 17 18 19 20 A 21 Q 22 23 A 24 25 Q ) 1 A 2 Q 3 4 5 A 6 Q 7 8 9 10 11 '12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 42 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? Page 43 Yes. Okay. And is that where you're going to be providing the details of the fluid composition is in the supplemental portion? Yes. 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 ) July 24,2001 Page 44 1 can identify for you the members of the Commission staff, 2 but..... 3 MR. POSPISIL: Okay. So the staff and 4 owner..... 5 MS. NELSON: I know I get to leave. 6 (Laughter) 7 THE CHAIRPERSON: Then I was going to suggest 8 we take a break right after that. 9 MR. POSPISIL: Okay. 10 (Confidential session) 11 (Resume public hearing - 11 :26 a.m.) 12 A (By Mr. Bakun) I would just like to make -- since 13 we're back on the public record, I would like to make 14 one adjustment to the typographic area, and there is a 15 water description section. 16 Q (By The Chairperson) On what page? 17 A On page 12, under well performance, the second 18 paragraph where it gives the gas rates for the Beechey 19 Point State number 1 well, those should both have a 20 decimal point and it should be 1.334 and 2.700. 21 Q 1.334. There's a decimal point between the 1 and the 22 3, and between the 2 and 7? 23 A That is correct. 24 Q Okay. Thank you. 25 A Thank you. And that concludes..... Page 45 THE CHAIRPERSON: Your testimony? Yeah. THE CHAIRPERSON: Thank you. (Witness excused) THE CHAIRPERSON: Raise your right hand. (Oath administered) MR. YOUNG: I do. JAMES PATRICK YOUNG having been first duly sworn under Oath, testified as follows on examination: DIRECT EXAMINATION THE CHAIRPERSON: Do you wish to be -- to provide expert testimony today? I A Yes, I do. THE CHAIRPERSON: 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 1 2 A 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 .J,: -,,-...' -,~ ~" ',", "'-."",.". -,. »u.=>Id,n.!,U«, ' ""............."","-",~....,,-_., ".'~"~~M=, ,,' ,. . ," ::.:,,'''''~', "'''''''','' """-,-".....,.""~,.~,...-=....,.",,,,., '-" v,..,,--.",,' . .~" :_"v -", \. _>,,~v-_r--.'---...,..-~y - -~...,." '" 1JI~~-'--r-'",,--"'ru'-...""""-"."- lO"'- ._.'~"--...~,-,:tit.\~""""-'V~V-M"'¡._"'..F"¡;(í$Ui,~""~'ffi>~~t~~'r"""~..~,.,..,-....,,,,, 12 (Pages 42 to 45) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ) AOGCC 1=RANSCRIPT OF PROCEEDINGS I " Page 46 ) 1 with the Greater Prudhoe Bay Western development area 2 since August 1999. I would like to be acknowledged as 3 an expert witness. 4 THE CHAIRPERSON: Do you have any questions? 5 COMMISSIONER HEUSSER: No, I don't. 6 THE CHAIRPERSON: Anyobjections? Mr. Young, 7 you're in the same position as the other witnesses have been 8 so far. Is there specific testimony that you would like to 9 have adopted as your testimony and just summarize, or would 10 you prefer to read it into the record? 11 A If you will allow, I would prefer to just summarize it 12 for you and give you the pages. 13 THE CHAIRPERSON: Well, for purposes of 14 adopting your testimony into the record, could you identify 15 which pages would be your testimony? 16 A The pages of my testimony begin with page 19, 17 facilities, continue through Well Operations, into 18 area injection operations, production allocations, and 19 -- and at the -- on page 34 at the end of the area 20 injection operation section. 21 THE CHAIRPERSON: Okay. So it would be page 22 19 through 34? 23 A 19-34, correct. 24 THE CHAIRPERSON: You may proceed to summarize 25 your testimony. Page 47 Okay. The Aurora wells will be drilled from the existing IPA drill site, S-Pad. In Exhibit 111-1 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. 1 A 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) -W''''','~~f''~'''_.'J\~i''~~~~~\'~'''''''I~~~WI'''.~~~~''~ '.. 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) July 24, 2001 Page 48 The water injection capacity available currently to 8-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 8ection 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 8-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, 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 49 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 8-100,101,102,103,104, and 8-105. The Exhibit Roman numerallV-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 8-100 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 ~~~a~,.n"..~."~,, mm"M-"'#rm"""~"""YÐ..",,~ym_.~ _..,-~............._-"...,,'(J' .-_...J. 13 (Pages 46 to 49) Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC 1:RANSCRIPT OF PROCEEDINGS I ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 . 19 20 21 22 23 24 25 ) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 50 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 thè 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 Page 51 recommend removal of the oil pool from the scope of that Conservation Order to be -- and this would also make it consistent with 5-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. All Aurora wells will ~ave 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 ) July 24, 2001 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 521 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 j 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 5-101 and the 5-1041 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 Page 53 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 completions for these wells. A cement bond log indicates good cement bond across the Kuparuk in the 5-105 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 5-105 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 I J L..-..- 'd""""""',. -.,---"=w.-,,.-....,...... 'Ii,,",' ", ',,,,,,,,,~~,,'.__m.u_",,,~,,,,,.........,,,,,-...-, -""-""""------"""'-_'1""",... --,'_.,,,"U" .."-""""'&"""~<;"""""""",""""~,,"-~-,,.._~~g..,, ~~-"-'T"-"--""-'-' mum_".,...' 14 (Pages 50 to 53) Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net ) AOGCC TRANSCRIPT OF PROCEEDINGS I ~~ ) 1 waterfloods on the North Slope. The Kuparuk reservoir 2 is bounded by the Kaluvik and HRZ shales above the 3 Kuparuk reservoir which have combined thicknesses of 4 greater than 110 feet in the Kuparuk area, and have 5 demonstrated with -- with logs and formation integrity 6 tests to have a fracture gradient of .8 to .9 psi 7 which would allow us to inject into the Kuparuk at 8 designed pressures, and not exceed this fracture 9 gradient. 10 The Aurora -- as mentioned earlier, the Aurora 11 Pool estimated to have 110 to 146 million stock tank 12 barrels in place, and simulation studies indicate 13 incremental cover to be between 15 to 25 percent of 14 original oil in place relative to primary completion. 15 The final section covers the proposed Aurora 16 Pool rules which we have submitted a draft for your 17 review. At this point, I would like to open up for 18 questions before we go into this, we can go -- step 19 through the pool rules. 20 THE CHAIRPERSON: Mr. Pospisil, do you know 21 did you receive an e-mail from Tom Monder (ph), a petroleum 22 engineer? It would have been late yesterday afternoon. 23 MR. POSPISIL: Yes, we did. 24 THE CHAIRPERSON: Okay. 25 MR. POSPISIL: And we have -- we can respond ) Page 55 1 to questions included within that e-mail. 2 A Yes, we have. We have a written response to those 3 questions, and we can -- I can go through which of 4 those you would like to, or all of them, as you wish 5 if you want to. 6 THE CHAIRPERSON: If - well, if they're in 7 writing, maybe we could just get some.- get a copy and..... 8 MR. POSPISIL: That's correct. We can provide 9 a copy. 10 A Okay. We'll have a copy, available copy. 11 COMMISSIONER HEUSSER: Mr. Young, I need some 12 clarification here. 13 BY COMMISSIONER HEUSSER: 14 Q Looking back at page 24 where it talks about the 15 proposed wells. They'll be concluded in a single 16 zone. I'm going to be referencing an earlier part of 17 your packet, page..... 18 UNIDENTIFIED MALE SPEAKER: (indiscemible) 19 Q Yeah. Okay. ltis page 24 on both packets. So the. 20 - you've got a discussion here that talks about single 21 zone completions and multi zone completions using a 22 single string and packers. And then you go on to say 23 that for multi zone wells, wells will have gas lift 24 mandrels to provide flexibility for artificial lift or 25 commingle production and injection. Could you clarify }---.....-- "~-~"""""".",~:",-,,,,,,,., ''\,~....,''--'"..'"--'''~ , 1 2 3 4 A 5 6 7 8 9 10 11 12 13 14 15 16 Q 17 A 18 Q 19 20 21 A 22 23 24 25 1 Q 2 A 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 A ) July 24, 2001 Page 56 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. Page 57 l' Po ~ When will you be bringing that information to us? 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? ..... - included that. I ~;:;It'~"h\\:W.'"'~~'''T~''''''' ""''''''H'''.',~" .v..-''''ïrli''~-'~ 15 (Pages 54 to 57) Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC TRANSCRIPT OF PROCEEDINGS I ) Page 58 ' 1 THE CHAIRPERSON'. ' So that would have been part 2 of the conservation order? 3 UNIDENTIFIED MALE SPEAKER: The summary and 4 the tables were. 5 A I forget what conservation order. Three, sixty-three. 6 THE CHAIRPERSON: There are two of them I 7 believe. 8 A Yeah. 9 UNIDENTIFIED MALE SPEAKER: Right. 10 A Two of them. 11 THE CHAIRPERSON: So it's been included in 12 that packet. Okay. So we have those on file. 13 A Yeah. 14 THE CHAIRPERSON: Has there been any work done 15 since then with respect to subsurface safety valves? 16 A Not to my knowledge. 17 MR. SMITH: No, the exact numbers - 18 (indiscernible - away from microphone) Petroleum, Borealis, 19 BP. The actual analysis that was done has been reviewed 20 coarsely, that the actual data was considered as similar. 21 That is, the actual evaluation has provided the same answer 22 for what we've seen. We've seen no change in the data base 23 for the consequences of this. So -- and the actual risk 24 analysis that evaluated in '74/75 -- or excuse me, '94/95 is 25 considered the same and still valid. Page 59 1 THE CHAIRPERSON: Okay. Thank you. Well, as 2 many of you know, the Commission and the State as a whole has 3 come under some scrutiny and criticism for its original order 4 back in the '90s for blanket releasing the subsurface safety 5 valves, and at least one state agency has called upon a 6 review -- a Commission review of that determination. So do I 7 understand then that your answers to these questions rely on 8 that analysis for the determination? 9 MR. POSPISIL: We were specifically asked to 10 provide information as far as a risk assessment so that area 11 of a risk assessment is based upon that '94 survey which as 12 Bruce mentioned we have reviewed more recent data, and believe 13 that that - the results and conclusions from that are still 14 valid. So that, we have updated that in terms of Aurora. 15 We've also looked at the specifics of the well designs and the 16 operations at Aurora, and our proposal is consistent with that 17 in terms of subsurface safety valve requirements. 18 THE CHAIRPERSON: What kind of safety valves, 19 surface safety valve systems are you using on those wells, the 20 Aurora wells? 21 MR. POSPISIL: You'll get that. 22 A (By Mr. Young) Hydraulically, the actuated wells with 23 a pilot system which shuts in the well down 24 automatically based on an upper limit pressure and a 25 lower limit pressure. ) ) " July 24,2001 Page 60 1 THE CHAIRPERSON: The reason I ask is I 2 understand from practices across the Slope that some fields do 3 better than others, and I didn't know if there was a 4 difference in hardware. 5 MR. SMITH: There is changes that are between 6 the different systems themselves. Both hydraulic and the , 7 electric system are now being evaluated for being installation 8 -- being installed for (indiscernible) and for other pads that 9 are in general, that the general design of the equipment 10 itself is similar to the other Prudhoe Bay installations 11 currently. 12 COMMISSIONER HEUSSER: So I heard you mention 13 electric pilots. Now, I believe that those are used at Nome 14 and they have a pretty good track record with respect to a 15 very low failure rate, and so -- but I think I just heard you 16 say that what's going to be installed for these wells is 17 similar to although perhaps more model version of what's 18 currently in place at the Prudhoe Bay field? 19 MR. SMITH: The pilots themselves on S-Pad are 20 electric. 21 22 electric? 23 MR. SMITH: That's correct. The hydraulic 24 system for the surface safety valve itself, the current 25 equipment that is in place is a hydraulic system at both Milne COMMISSIONER HEUSSER: The pilots are I Page 61 ! 1 Point and at Prudhoe. So - but the pilots themselves will be t 2 electric, and that's the current system. The hydraulic 3 systems for the pilots themselves have been phased out, and 4 they've been changed over to electrical, all new installation. 5 COMMISSIONER HEUSSER: Thank you. 6 COMMISSIONER HEUSSER: Could we be provided 7 with a copy of the results in whatever level of detail is 8 appropriate of your recent subsurface safety valve assessment? 9 MR. POSPISIL: Sure. 10 BY COMMISSIONER HEUSSER: 11 Q I have a question with respect to the proposed level 12 of reservoir surveillance, reservoir pressure 13 surveillance. Okay. I believe I heard you say that 14 you'll be taking - you propose to take two pressure 15 measurements on the west side of the north - the main 16 north-south fault, and two on the east side, is that 17 correct? 18 A (By Mr. Young) Well, it's two total, so it would be 19 at least one on each side. Two in the field, a 20 minimum of two pressure surveys in the field, and one 21 on each side. 22 Q For my own curiosity, since you've identified 23 stratigraphic blocks, five different ones, why aren't 24 you concerned one per stratigraphic block? 25 A (By Mr. Young) We most likely will for surveillance ~ t f r ~ ""'~*'--t....",(", '-"'~~"'t\'~~''''''''''~~-'''''-'~*i~''~'i..~~~~~''~'t~'it-'''''''''''''''''''t.}--'F~-'-~--~-.-..Imm ....._-._-_...........~ "''I.._'''~'--'..........-''...mm.. '~~'-"""~~~--~'''''~'.'''':~ii','''':.<D'''¥¿W''"''''''''''''J'('fI¡('''-I,'~.~"'M.""W"-'''''''''''\Q.~';¡ 16 (Pages 58 to 61) Phone (907)276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC 'tRANSCRIPT OF PROCEEDINGS ) I ) 1 2 3 4 5 6 7 A 8 9 10 11 12 13 14 15 16 17 18 19 20 Q 21 22 23 24 25 A ) Page 62 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 1 2 3 4 5 6 7 8 9 10 Q 11 12 13 14 A 15 Q 16 A 17 18 19 20 21 22 23 24 25 ) ,- -_...~~~. . ''''''~~'t~'\W''''~'' '."m I~)).~ ~'V" .--. Page 63 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 iL... 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- ....._n__U '~'~"'Ilr"""".~--~~-,~""""",,~ .> July 24, 2001 Page 64 104 as mentioned in Jim's testimony, it will be converted to water injection. 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? 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 1 2 3 Q 4 5 6 7 8 A 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 I I I Page 65 , 1 begin water injection? 2 A We would like to start the first week of August. 3 THE CHAIRPERSON: First week of August, okay. 4 With respect to -- let me look at the pool definition and the 5 affected area for injection, I just want to verify what I 6 think looks to me like just a typographical error, but on your 7 Exhibit 1-3, or 1-3, it appe~rs to me that the pool 8 boundaries, the rule boundaries and the area injection order 9 boundaries that you are looking for track the surface 10 boundaries of Exhibit 1-3, is that correct? 11 A (By Mr. Bakun) That's correct. The -- it ineludes 12 the initial or our participating area which is in the 13, solid line, plus all of the area in the dashed lines 14 for the automatic expansion areas. 15 THE CHAIRPERSON: I tend to get lost on 16 multiple lines of repeated numbers, when I look at the actual 17 affected areas that's described there, it looks to me like 18 Section 30 is not on there. 19 A It's just a corner of expansion -- automatic expansion 20 area four. Is that..... 21 THE CHAIRPERSON: That's correct. That looked 22 to me like it was left out, but I may have missed it going 23 over all those numbers. I just wanted to confirm that that 24 should be included. 25 A (By Mr. Young) Good point, yeah. Have to look. it I ~ '¡o If i I *.;s>..,~\'Wo:.....,.¡.V;.;.'¡W~$~',}N..~~.;~,'í$"."" 17 (Pages 62 to 65) Phone (907)276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC :rRANSCRIPT OF PROCEEDINGS -l Page 66 ) 1 should be included. Yeah, we may have left it out on 2 the description. 3 THE CHAIRPERSON: Well, it's easy enough for 4 us to fix. We just wanted to make sure that we were adding it 5 correctly. 6 MR. POSPISIL: Right. That's correct. That's 7 our intent. 8 A Yeah, what's on the map is correct. 9 A (By Mr. Cerveny) Yeah, I think you're right. 10 THE CHAIRPERSON: The only other -- just a 11 minor detail. Sorry. On rule number two of the pool rules 12 with the proposed pool definition and under rule number one 13 for the area injection application, referring to the 14 authorized injection strata, you're using the V-200 well but 15 the depth that you used for the pool definition is the lower 16 number 7,253.5. You're using 7252 for the area injection 17 application. 18 A (By Mr. Young) Probably just a rounding error. 19 THE CHAIRPERSON: Okay. As long as there 20 wasn't a specific reason that we were looking for that. 21 A No. 22 THE CHAIRPERSON: Okay. And then with respect 23 to the additional information that the Commission has 24 requested, how much time would you ask that the record be left 25 open so that that information can be provided? Page 67 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 A 22 Q 23 A 24 Q 25 ) ~~~~~~:ii¡¡i*""""'" ~T' 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 alii 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? (By Mr. Young) It's once per month. Once per month? Yeah. So page 36, first paragraph 0 where it specifies well test two times per month, that should really be one? h...'~4~.""'r-"""""-~ i'"l.'f'i'X.xKr''(.m.,",",\~ 1 2 A 3 4 Q 5 6 7 8 9 10 11 12 13 14 A 15 16 17 on? 18 A 19 20 Q 21 22 23 A 24 25 A 1 A 2 3 Q 4 5 A 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ) July 24, 2001 Page 68 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 11-1, 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. Page 69 (By Mr. Cerveny) .....sidewall cores and a number of wells. Out of curiosity, was different core data used to calibrate for Borealis interpretation? 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 ,~WNL{..".{IIt'i:rA'J'bi~''''''''~._HI!{~V'''~ . ,-, --''fI~ ..--, n___."'Ø'"'" "'-.--. "-'''-''''''''''í(r~ "":"~- ï'Þ-..v...-..n,'" 18 (Pages 66 to 69) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC tRANSCRIPT OF PROCEEDINGS July 24, 2001 Page 70 i 1 CERTIFICATE 2 UNITED STATES OF AMERICA) )55. 3 STATE OF ALASKA ) 4 I, Laura C. Ferro, Notary Public in and for the State 5 of Alaska, and Reporter for Metro Court Reporting, do hereby 6 certify: 7 That the foregoing Alaska Oil & Gas Conservation 8 Public Commission Public Hearing was taken before myself on 9 the 24th day of July 2001, commencing at the hour of 9:00 10 o'clock a.m., at the offices of Alaska Oil & Gas Conservation 11 Commission, 333 West Seventh Avenue, Suite 100, Anchorage, 12 Alaska; 13 That the public hearing was transcribed by myself to 14 the best of my knowledge and ability. 15 IN WITNESS WHEREOF, I have hereto set my hand and 16 affixed my seal this 3rd day of August 2001. 17 18 Notary Public in and for Alaska My commission expires: 06/03/05 19 20 21 22 23 24 25 l(.,,' (\ I ! ~. ¡ ~~~"'~rW:U"""'~:\~'~Iør:~~~"'~"""""~"''''iir~~~'''''''~''U_'-''~~'~'r!rr'~~'1f'Nf-"~~-".r{1'''~~''~~:-W1rtLY:~-"]'¡:~~'YW'~'''''''''''''''''''''-''--'1I1_''1.~J'tfrr-~~""""'m..9 19 (Page 70) Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ( AOGCC July 24, 2001 tRANSCRIPT OF PROCEEDINGS I --.--- '-X----------' agency 59:5 applications 47: 13 22:2244: 13 47: 16,20 biocerbated 12: 1 J <\.AC 50:1552:7,23 - ago 57:19 appreciate 57: 17 69: 12 48:21 55: 14 59:4 bisecting 16:7,12 I ability 70: 14 ahead 3: 13 43: 10 approach 40:23 badly 35:21,25 bisects 15:6 able 48:2263: 1 AI 6:837:8,13 appropriate 61:8 bakun 21:2523:21 bit 39:5,10 about 23:19 24:7,10 air 28:6 approval 52:7 56: 12 24:325:21,2226:7 black 8:22 14:24 25:842: 15 55: 14,20 alaska 1:1,8 3:17,18 approved 48: 11 31:21 38:2043:7 blanket 59:4 ~ 63:2064: 12 4:11,21 5:1 26:9,14 approximately 2:6 44:1257:2262:7,25 block 16:2,5,6,9,10,14 above 10:5 18:15 19:13 45:19,2452:1456:8 15: 14 17: 1228: 19 65:11 16: 16,16,17,21,22,24 23:23 24: 1 54:2 70:3,5,7,10,12,18 29:7 33:7 38:6,13 balance 40:21 16:25 17:3,15 19:12 accept 29:21 Alaska's 5:12 40:5 63:25 balanced 62: 16 19:1420:1422:12,13 acceptable 52:9 64:21 allocation 48:9,16 aquifer 40:4 balancing 62:24 63: 1 22:15,1523:10,12,14 accepted 2:20 51 :24 52:6 ARCO 3:174:2445:24 barrel 33:14,15 34:6,8 23:15,2424:3,4 29:10 accordance 51:852:23 allocations 46: 18 56:24 arctic 50: 18 34:936:18,21 37:3,6 37:13,14,17,2538:11 according 33:1852:1 56:24 area 1:5 2:7 3:19 6:3,24 37:2238:5,18 51:18,19,19,2061:24 accumulation 6: 12,18 allow 46: 11 53:23 54:7 6:25 7:3,5,8,8 10: 14 barrels 33:1534:7,9,10 62:863:17 14:8 15:19 19:18 allowed 43:25 10: 18 14:4,16,21 34:2335:14,1436:6,7 blocks 15:3 19:1 20:12 20:2121:933:24 alone 62:9 15:15 16:2,3,5,5,10 36:8,16,2037:1,5,21 22:10,16,2423:3,19 acknowledged 5:4 along 17:5 28:18 31:21 16:22 17: 13,21 18: 11 38:4,1740:8,14,15 23:2524:10,1661:23 26: 17 46:2 35:13 19:223:6,1226:20,24 48:5,23 49: 1 54: 12 63:268:12 ACL 51:13 already 57:662:7 43:1644:1446:1,18 base 7:23 8:8 13: 14,24 blue 17:25 18:9 acquired 2:12 alternative 52:9 46:1952:10,14,17 58:22 62: 12 Bluff 17:23 18:8 50:7 acquisition 45:2448: 18 although 60: 17 54:456:859:10 based 18: 18 19:4,7 50: 12 56:21 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22:1623:14,1925:8 68:21 ~ 22:23 31:5 63:25 Applicant 2:16 b9:9,2110:1411:9,13 30:1234:2344:21,22 call 2:3 against 15:21 19:20 Applicants 50:25 25: 1 26:8 48:15 52:454:13 called 9:14 10:114:7 f 32:13 application 2:7 3: 19 bachelor 4:21 26: 11 56:1960:5 59:5 t .ge 8: 14,15 29:19,2549:764:23 45:22 beveled 15: 17 cammy 1:11 2:9 ' I aged 8:9 66:13,17 back2:23 9:11 22:12 billion 48:25 -,-~ ~~'r1:"'r"'nr"Ut1'.1M\'It~{t«'(~Mì~{~~'>W~.11.r~'Wi'n-~~~~¿lNV«rrffif.'f¡I -¡.. -- {:"Wiß;¡:~~~.::"¡: 1iì .. *'~~~,~ _(H<~ Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC TRANSCRIPT OF PROCEEDINGS I capable 56:5 capacity 48: 1 49:4 capillary 31 :2432:3 case 56:22 casing 49: 11, 12, 14,21 49:25 52: 18,22 ceiling 63:4 cement 53:2,2 cementation 9:3 12:16 cemented 50:3 centipoise 33:1634:4,4 34:5 certainly 39:6,1467:7 certify 70:6 cerveny 3:21 4:2,3,10 22:2,3,466:9 68: 14 69:1 chairperson 1: 11 2:3 3:5,9,13,234:7,12,15 4:185:6,921:12 25:16,1826:1,4,23 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METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net ( ( AOGCC TRANSCRIPT OF PROCEEDINGS I develop 42:9,11 47:23 37: 16,2438: 1047: 1 entire 10:24 37:9 experts 42:3 finding 14: 12 t (developed 27:14 47:21 49:7,2351:10 enviro 50:18 expires 70:18 finds 12:24 f i jevelopment3:154:20 51:13 environment 50:18 Exploration3:184:11 fine8:411:2213:3,5,14 L,.. 5:36:7 15:9 16:8,20 drilling 5:21 24:18 62:1563:8 4:20,2526:945:19 13:15,18,24 F 26:1135:937:17 35:2537:1838:1,12 EOR47:12 extend 47:14 finest 12:25 ~ 38:1,1239:2141:1 drive 40:3 equipment 60:9,25 extensive 62:6 finish 64:14 f, 45:2146:149:7,20 drop 40:7 equipped 51:4 extent 43:19 fired 69:11 ~ . 62:1463:14 dropping 34:15 eroded 10:9 e-mail 54:21 55:1 first 2:173:10,17 4:4 ~ developments 26: 16 due 12: 14,22 13:25 erosion 10:22 e-n-y 4: 14 6:5 16:825:23 29:24 27:550:16 14:1433:21 34:24 erosional 9:19 36:541:1545:9 devoid 15:19 38:863:21 error 65:666:18 .t' 49:1965:2,367:10,10 diagnostic 51:22 duly4:425:2345:9 essentially 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33:23,2534:1240:10 35:13,15,18,19,19 forms 18:5 dividing 6:1051:18 Eleven 37:12 47:249:9,1852:15,17 36:2,9,13,16,17,19,19 forward 2:2456:6 doctor 4:23 eligible 31:15 53:765:7,1068:9 36:21,2537:1,2,6,19 four 36:1465:20 document 21:5 29:23 eliminated 50:19 exhibits 21: 17,2225: 13 37:2238:2,5,7,14,18 fraction 27:22 29:25 30:639:8 57:7 employed 4:2432:23 30:7,931: 17 52:25 48:24,25 49: 12 54:4 fracture 54:6,8 57:11,1967:17 encompassed 7:5 existing 47:2,19,22 felt 62:4 fractures 53:22 dominated 11:10 13:2 encountered 36:11 49:351:468:21,22,23 Ferro 2:1070:4 frank 4:3,10 done 51:2557:1858:14 end 14:646:1947:15 expansion 7:3,820:4 field 1:43:227:613:9 frederick25:2226:7 58:19 57:264:1269:14 65:14,19,19 15:1420:321:223:7 free 18:2424:19,22 down 5:196:19 15:5 engineer 26:9,1027:2,4 expansions 40:3 24:2240:7,2442:20 36:12 19:2320:2459:23 27:645: 19,2054:22 expect 62: 1664:5 67: 1 47:2449:2050: 16 freshwater 53:24 downhole 33:10 engineering 26: 12,21 expected 11:729:9 51: 17 60: 18 61 :19,20 from 2: 104:22,23 7:6 downward 9:20,23 26:22,2445:22 33:248:249:353:13 62:14 7:178:179:5,9 11:18 10:7 14:9 enhanced 52:21 53:6 53:21 fields 23:660:2 12:4 13:7,13,20,24 tfraft 54:1664:21 enough 66:3 experience 50:17 file 57:21 58:12 14:25 15:117:12 ( :iIl47:2 entail 51:15 expert 2:184:165:4,9 filed 29:2357:19 18:3 19:11 21:24 I drilled 6:48:1 16:4 enter 68:13 26:2,18,1945:13 46:3 final 37:4 51:24 54:15 23:21 26:1227:14,20 ~~!;IU(. ~,}'~~¡~~_U'ii'~t1'U'L'4'~r."~~~~;¡"-~"~~~~'Yr"1t'Viw:'nm-_ti'tf'\)~'W'I«'~'1ft'tímf!<'ii'VI~~~'«~'''&..~~''''''''''' .. ¡: LríH~~1tt\f'~~t't1"'í:..m-''¥'''''''''~_1;;.A July 24, 2001 Phone (907) 276-3876 METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC July 24, 2001 TRANSCRIPT OF PROCEEDINGS 27:23,2528:7,13,19 43:21 44:7 55: 16 high 15: 12, 14, 16, 18,21 indicating 13:6 introduce 3: 11 ( 28:20,24 31 :2432:8 60:1663:1,1264:13 36:1 indiscernible 21 :23 introduction 3:22 5: 11 32: 12 33: 1,4,9,19,19 64:17,1865:2268:20 higher 8:6 11 :6,8 23:21 24:3,5 55:18 involves 15: 13 34:335:1,2,1936:1,3 good 24:23 53:260:14 highest 14:2 58: 18 60:8 IPA47:2 36:9,10,12,21 37:3,6 65:25 67:6 highlight 49:6 influenced 10:22 irregular 63:20,21 64:4 37:12,13 38:2140:4 GOR33:13 34:17 highly 8: 15 influx 40:4 isolated 37: 13 63:3 41:742:2145:23 36: 17,2037:2,5,21 hold 29: 15 informally 7: 11 isolates 50: 11 47:1,11,14,15,2148:6 38:4,17 hole 7:1636:1549:24 information 30: 11 31:2 it'll 31 : 19 39: 11 49:2,1650:11 51:1,17 Gordon 3: 14 hoping 42:3 64:25 31:843:2257:1 Ivishak 6:6 15:9 16:14 51:17,1953:8,954:21 governing 50:20 horizon 16:12 17:21 59:1066:23,25 67:8 17:2 18:13,1450:7 56:13,1957:2258:18 gradatially 12:23 35:23 69:10 53:1256:20 59: 13 60:2 gradient 18:23 19: 11 horizons 18:7 initial 32:5,7,7 33:3,4 IV-149:9 front 2:24 37: 11 54:6,9 horizontal 16:8 28:10 34: 1 36: 15 37:20,22 IV-2 49:1852:25 full 4:8 21:2045: 16 gradual 12:23 37:16,2438:1049:18 38:7,1841:2447:25 IV-3 52:25 function 34: 13 grain 11:22,22 12:18 49:23 50:2 65:12 IV-4 53:7 functions 32: 1 12: 19,25 13:3,14,15 hour 64: 11 70:9 initialize 32:4 1-1 5: 13 ff fundamental 33:25 13:18,24,25 14:1 hours 36:6 initially 40:6,13 52: 19 1-1020:6 further 12:3 24: 18 grained 8:4 12:8 13:6 HRZ 8:16,21 10:4,9 initiate 53:21 1-1120:17 36:2553:3 grains 12:20 19:21 54:2 inject 40: 19,21 52:21 1-12 20:6,22 future 24: 13 47: 1250:6 gravity 32:1433:12 hydraulic 53:1960:6 54:7 1-1321:3 56:1968:11 34:236:1037:14,23 60:23,25 61:2 injectant 41 :2542:6 1-26: 13 14: 19 17:6,18 38:7,18 Hydraulically 59:22 injecting 56:2 18:421:17 G gray 8:20 hydrocarbon 21:3 injection 1:5 2:73:19 1-37:2 65:7,7,10 G2:1 great 39:22 hydrocarbons 6:5 31:2340:15,1941:23 1-47:169:4 gamma 8:20,22,23 greater 5:28:2326:16 34:18,19 42:646:18,2047:10 1-515:2521:1722:22 27:18 32:2,1940:2046:1 48:1,350:6,11,12 1-6 17:4 gas 1:1 19:1634:4,9,16 54:4 1 51:6,752:10,18,20 1-717:16 34:16,2535:2,2,13,15 green 17:22,22 18:8 idea 63:12 53:5,11,15,16,21,23 1-8 18:2 37: 1038:940:2,3 gross 14:3 28:23 29:5 identified 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METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 July 24, 2001 19:25 predates 10: 19 prefer 39:346:10,11 prepare 43: 18 ~ presence 6:9 l present 2:163:18 7: 15 ~ P:'~~~t~~~~:~~ :~9~~:6 t presented 3:241:18 ¡ 43:15 presenting 41: 12 pressure 18:23 19:11 22:17,1923:1931:24 32:3 33:3,4,11,17 34:1,13 35:2036:12 36:2440:6,2047:9 48:753:16,19,21 59:24,2561:12,14,20 ; 62:21 pressures 34: 1737: 11 50:11 51:1653:15 54:862:13 pretty 60:14 previous 17:1828:18 primarily 34:2441:17 53:11 primary 11:1620:9 39:2540:1 54:14 prior 27:5 62:11,22 probably 24:1643:9 63:1 66:18 problem 39: 17 procedures 27: 17 proceed 27:1231:12 45:1746:2464:17 proceeding 3:12 proceedings 1:7 2: 11 2:1669:14 process 33:21 40:22,23 42:2 48:22 processed 48:22 processes 10:24 produced 36:5,7 37:20 38:3,1649:1953:7,10 53:11,12 producing 35:12 40:8 56:2 product 9: 17 51 :24 production 4:2527:2 35:936: 18,25 37:4 38:3,8 40: 13 46: 18 47:4,7,8,19,20,25 48:9,14,20,21 49:2,25 50:1 51:2452:1,5 53:955:25 56:9,13,14 56:18,2467:16,19 productive 7:10 11:8 productivity 12: 17 : 49: 17 r profile 42:9,12,14 I program 51:15 : progressively 9:24 ~ 36: 14 [ project 26: 11 45:21 , ~~~~~" .J metro@gci.net AðGCC ;r'RANSCRIPT OF PROCEEDINGS (' I projects 5: 1 26: 15 45:25 promise 67:9 propagate 53:22 properties 33:23 34: 13 34:2142:16,17,18 68:8,10 proposal 59:16 68:1 propose 56:1261:14 proposed 20:4 52: 19 54:1555:1556:8 61:11 63:11 66:12 proposing 56: 16 proprietary 31: 1,2,3 43:22 proven 24:18 provide 2:19 16:20 26:1,542:15,1745:13 55:8,2456:459: 10 62:23 67:2 provided 30:1 43:15 58:21 61:664:20 66:25 provides 33:2548:7 ' providing 21:1742:10 42:1043:2,21 69:10 prudent 51 :21 prudhoe 1:4 3 :20 5:2 5:16,236:227:6 15:12,13,14,2126:16 27:3,632:1642:6,22 46:1 47:8 50:20 60:10,1861:1 psi 37:12 48:453:16,18 53:2054:6 psia 33:5,11 34:1 psig 33:20,20,2234:15 48:7 public 1:22:1429:15 29:1731:844:11,13 70:4,8,8,13,18 published 2:15 purposes 9:8 31: 12 46: 13 62: 1, 1 pursue 64:22 put 22:1243:1251:6 68:16 pvd 42:8,12,14 pvt 33:8,834:1236:23 pom 69:13 ( ( I Q qualifications 2: 19 4:1926:645:17 quality 10:25 11:3,8 12:11 14:327:17 38:15 quarter 52: 12 quartz-rich 8:4 11:24 question 21:1661:11 68:4,10 questions 2:21,245:7,8 21:13 25:15 27:8 39:441:5,9,10,17,17 43: 15,1646:454: 18 ~~~: ~.¡tf~ ~ v(6-~.vJ 1\ Phone (907) 276-3876 55:1,357:5,6,12,14 59:764:1069:7,8,11 quick 39: 19 quickly 63:016 R R 2:1 70:1 radioactive 8: 16 radius 52: 13, 16 raise 3:2525:1845:5 range 13:13 18:2524:8 35:1942:17,1849:15 ranged 28:1336:10 ranges 11:18 34:23 35: 1,2 ranging 28:19,2032:8 33:1934:249:16 rate 37:540:8,1548:22 49: 1 60: 15 rates 40:13 44:18 48:3 48:4 ratio 28:1033:13 34:5 ratios 28: 13 ray 8:20,2227:18 Re 1:3 reaches 16: 13 read 46: 10 readable 21: 17 reading 38:21 39:15 really 23:1524:1862:2 67:25 69:11 reason 60:1 64:666:20 reasonable 21 :20 reasonably 29:9 receive 54:21 received 4:21 26:11 45:21 recent 6:259:1261:8 recombined 33:9,21 recommend 51: 1 record 2:2 4:9 26:5 29: 15 31:7 39:8 43:11,1244:13 45:16 46:10,1460:1466:24 67:469: 13 recorded 2:11 3:7 29:17 recorder 4:9 records 57:22 recover 40:5 recovery 39:25 40: 1,1 40:11,12,2542:1 52:2253:6 red 17:24 18:8 reduced 12: 17 refer 23:9 reference 64:20 referenced 42:8 referencing 55: 16 referred 7:1232:18 referring 6:21 66: 13 reflect 34:19 regulation 50: 15 relative 32: 10,10,21,25 54:14 1 I: ~'%'mr.ffif"t'ä1'_'~f..4 ( July 24, 2001 relatively 14:1 23:11 64:20,20 saturations 19:5,10 . 32:24 reviewed 58:1959:12 27:2031:22,22 32:5,7 ~ releasing 59:4 reviewing 57: 11 save 39:5 " rely 59:7 RFT 18:22 19:11 33:4 says 21:5 ,~ remain 3:2343:13 33:10,1836:1237:8 scale 5:196:1920:11 i, remember 63:10 37:11,14 21:20,20 ,~ removal 51:1 ridge 14:22 15:2,4,24 scaled 7:19 ~ ~:::::;:ln° rii~¡~:\t~:25 5:19 7:1 :~:~".:.;~~~752:24 t removes 9:21 21:2525:3,1929:15 Schrader 17:23 18:7,15 ~ removing 9:24 29:1642:1544:8 50:7,1256:21 Repeat 18:22 45:556:1758:9 science 4:22 26:12 repeated 65:16 63:1966:6,9 45:22 reporter 68: 1670:5 risk 31:8 57: 18 58:23 scope 51: 1 Reporting 2:10,13 70:5 59:10,11 screenings 41:24 representative 2:23 River 5:16,226:2,6,8 scrutiny 59:3 representing 4:8,10 7:6,11 8:18 15:9 sea 14:1653:12 request 30:25 52:6 16:1417:2418:9,14 seaI23:529:2470:16 57:20 28:1 50:21 53:14,25 seated 2:233:23 requested 64:666:24 road 47:23 second 29:1535:16 requesting 30:8 roads 47:23 36:7,2238:1,21 44:17 require 50:24 rock 12:14 21:7 32:1,18 secondary 20:18 required 47:23 48:3 32:18,20,2234:21 secondly 43:18 requirement 50:14 role 3:16 12:11 section 14:10 17:5,7,18 52:8 Roman 49:968:9 18:10 19:2341:3,7,10 requirements 50:19 room 2:24 31:1443:25 42:24,2544:1546:20 51:859:17 rotated 15:3 48:1049:5,2350:2 requires 48:12 rounding 66:18 51:2452:1054:15 resemble 32:17 routine 28:5,12 63:14,1665:18 resembles 32: 15 rule 50:23,23 65:8 sectional 18:4 reservoir 5:21 10:25 66: 11,12 sedimentary 9:2 11:3,9,16 12:11 14:3 rules 1:52:73:197:7 sediments 8:3 15:16 17:1,919:20,23,25 50:2054:16,1962:2,3 see 17:6,11,18 18:3 20:10,13,15,2325:4 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13:1520:8,17,20,22 several 19:19 62:14 64:22 25:453:963:4,4 shale 8:12,20,22 9:15 responses 68:12 sands 11:5,14,16,24 19:21 responsible 3:15 20:10,1832:1735:21 shalely25:2 restore 40:20 35:25 shales 8:1719:2054:2 result 10:23 31:9 sandstone 8:4 11:11,22 shallow 24:450:12 resulting 53:18 12:1913:6,12,13,18 shallower 49:12 \ results 27:2039:24 13:24,25 20:6 shore 8:3 ~ 42:359:1361:7 sandstones8:613:21 short 63:17 ~ Resume 44:11 sandy 11:10,23 show 11:13 18:12 32:6 ~ return 28:21 satellite52:167:16 39:20 ill review54:1759:6,6 68:3 showing5:137:8,24 r ~~(¡W:ò UJ Jí¡~ u Ul~-"~- ~~Ì:~W1.~~"~«(N".."".'~~(<<,~J"""""F-q-:~"':'.,~..¡.W4'(~{"\'''~1-~¡~ it ....II-&~"-mtrff"'W'M_--'~ METRO COURT REPORTING, INC. 745 West 4th Avenue, Suite 425 metro@gci.net AOGCC TRANSCRIPT OF PROCEEDINGS July 24, 2001 ( 20: 19,24,25 30: 11 39: 1641 :5,842:4,8 statics 62:8 suggested 24:7 47:452:15,25 42:15,2350:551:9 stay 43:25 suggesting 10:18 ihown 5:156:13 9:3,8 55:7,11 57:14,1959:3 steady 63:8 Suite 2:570:11 9:10,19 11:4 14:24 60:264:567:8 step 54:1864:19 summarize 39:446:9 15:25 17:21,24,25 something 57:21 still 56:22 58:2559:13 46:11,24 18:8,932:552:24,24 somewhat 13:8 62:17 summary 33:2358:3 T 70:1,1 shows 6:207:2,16 sonic 27:16 stimulation 51:11 supplement 25:10,11 table 2:83:6 17:19 18:4,1620:13 soon 64:25 stock 33:14,1534:6,8,9 30:10 tables 58:4 20:1428:14,1629:4 sorry 31:466:11 34:2336:17,21 37:3,6 supplemental27:24 tailor 63:22 29:1033:2340:10,11 sort62:13 37:2238:5,1854:11 30:1431:1742:23,25 take41:1044:857:4 47:1749:9 sorted 11:25 straight39:448:14 43:4 61:14 shuts 59:23 source 42:5 strata 53:22,24 66: 14 supplied 48:6 taken 24: 15 70:8 side 6:9,209:9,10 16:11 south 10:24 16:7 strategy 40:18,22 supply 47:9,10,11 takes 23:347:19 36:351:17,1861:15 southeast 12:22 13:10 stratigraphic 7:189:5 sure 31:1439:261:9 taking 43:8 61:14 61:16,19,21 14:22 17:4,17 19:25 10:15 14:10 18:7 66:467:12 talk23:18 siderite 12:9,1029:3 20:19,25 19: 1834:2061 :23,24 surface 33:9,2236:23 talking 24:663:2,4 sides 22:18 southeastern 6:11 stratigraphically 9:1 51:752:12,1653:15 talks 55:14,20 sidewall 19:10 68:25 15: 11 16:25 20:2,16 stratigraphy 7: 109: 18 53: 17 56:25 59: 19 tank 33: 14,1534:6,8,9 69:1 southeastward 14:17 17:20 60:2465:9 34:2336:17,21 37:1,6 signature 8:21,23 15:21 strike 18:2 surrounding 8:7 37:2238:5,1854:11 significant 10: 1924:21 southern 15:437:25 striking 14:23 15:5 surveillance 40:23 tape 31: 14 41:20 southward 15:20 string 49:13,1455:22 51:15,2061:12,13,25 tapes 43:11 siltstone 8:5 11:i0,23 southwest 15:2 18:3 structural 11:6 12:15 62:5,10,12,21 taylor 1:11 2:9 silty 11:23 13:3,6,12,14 19:2220:20 15:1,13,16,18,23 survey 59:11 team 5:326:16 13:18 southwestward 10:25 16: 13 17:5,6 18:5 surveys 61 :20 Tech 45:23 similar 13: 1649:22 space 63:20 19:1723:8,16,16 suspected 35:24 technology 4:25 50:17 53:2558:2060:10,17 spacing 63:2564:4,7 34:20 Swear 3:8 tell 38:25 simulation 28:15,17 SPEAKER 21:23 55:18 structurally 16:1,5,24 sworn 2:18 4:4 25:23 telling 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unevenly 12:13 13:3,5,14,1824:25 56:14,1559:1,15,23 working 5:2 26:10,15 j , :ansitions 13:5 UNIDENTIFIED 25:1,2,457:1660:15 61:1863:2364:4,5,6 45:20,2547:10 56:22 ~ " I trap 19:16 21:2355:1858:3,9 67:669:9,9 66:3,1467:10,20,24 wouldn't 62:16 ~ ~~~~~~~~~~~~f"~~~~~«fYhY""'{f:o\nt'n_::~~I'~"t1~tfiF"'';¡-'1<''r1':~~)'t~~~~~.u~-'\¡,,~¡:W~~\{I(_W~~~~)MX;"i(,r July 24,2001 Phone (907) 276-3876 METRO COURT REPORTING, INe. 745 West 4th Avenue, Suite 425 metro@gci.net AðGCC July 24, 2001 ~RANSCRIPT OF PROCEEDINGS (' I writing 2:22 55:7 21:1,1,1 39:11,12 222: 15 6,4506:14 16:13 I written 55:257:5,6,17 43:947:9 23 18:25 6,631 19:7 Wyoming 4:24 1002:5 16:923:424:20 23rd 39:8 6,64835:19 35:1 70:11 24 1:82:447:855:14 6,678 19:935: 18 X 10149:8 55:19 6,68036:1938:7 x-ray 27:22 10235: 11 49:8 24th 70:9 6,693 7 :22 10349:8 25 14:2028:1934:3 6,70033:5,11 i'" y 10449:864:1 48:4 54: 13 6,70535: 19 yeah 22:1231:345:2 1056:24 25.03052:23 6,812 18:2036:9 55:1958:8,13 63:16 1142: 15 25.2 36: 10 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28:14,18 29:5 1946: 16,22 30 11:429:3 32:834:3 74/7558:24 53:2555:16,21,21,23 19-3446:23 65:18 7535:1,2 !,( 56:7 1969 6:4 30,00040:1548:4 ~ _ones 25:556:11,13 1971 50:24 32 36:7 H 19904:25 32048:23 854:6 0 1991 5:2 333 2:5 70: 11 808:21 49:11,11 64:4 0.006 28: 11 199245:25 3440:1246:19,22 83137:21 0.428:13 199626:14 346434:14 ¡ 0.5 29:4 199726:15 348 50:22 9 0.72233:16 19993: 17 5:2046:2 36 13:867:24 954:6 0.84334:10 363 50:22 9,00040:8 022 34:5 2 38736:16 9-5/849:12 06/03/05 70: 18 26:177:9 18:2235:7 9:00 1:9 2:6 70:9 35:2244:22 4 9:06 2:2 1 2,00040:748:3 46:107:9 90s 59:4 16:47:88:12 17:11 2,10048:4 4-1/2 49:24 94 59: 11 19:9,1428:3,830:10 2,30049: 12 4.34534:7 94/95 58:24 35:7,1236:144:19,21 2,50038:2 4:0067:4 96 26:23 1,00034: 11 2-01 28:9 4029:2 64:7 98A 7:7 1,06238:3 2-128:13 400 38: 13 98(a) 50:23 1,20538: 17 2-3/849:16 400,00048:23 1,50037:18 2.735: 15 4534:4 1,51736:20 2.70044:20 45838:16 1,80053:16 2011:421:228:11 32:2 4738:7 ~ 1,801 37: 1 32:19,2036:1840:15 480 63 :20 ~ 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METRO COURT REPORTING, INC. Phone (907) 276-3876 745 West 4th Avenue, Suite 425 metro@gci.net ::t:t: 0\ C) BP Exploration (Alaska), Inc. 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 July 23, 2001 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 '-' , bp RE: 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 Position Ops. Eng. Dev. Geologist Facility Eng. Geophysicist Res. Eng CC: Randy Frazier (BP) J. P. Johnson (PAl) Office 564-5754 564-5972 564-4350 564-4517 564-5173 M. P. Evans (ExxonMobil) P. White (Forest Oil) () ,-' , ~~a Aurora Pool Rules and Area Injection Order ~) Aurora Pool Rules And Area Injection Application July 23, 2001 7/23/2001 ii4û C.') 6,) L Aurora Pool Rules and Area Injection Order 7/23/200 I 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 IIljection 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 () ~ '1 Aurora Pool Rules and Area Injection Order 7/23/200 1 I. Geology Introduction The Aurora Pool is located on Alaska's North Slope, as illustrated in Exhibit 1-1. 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 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). 3i4û f } ,C) , -.) Aurora Pool Rules and Area Injection Order 7/23/2001 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 Band 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-l 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 Injection Order 7/23/200 I 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 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; theA-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 7/23/200 1 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 from oldest to youngest: C-l, C-2, C-3A, C-3B, C-4A, and C- 4B. The C-l overlies the Lower Cretaceous Unconformity. The Kuparuk C-l 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-l 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-l 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- 6i4U r) u Aurora Pool Rules and Area Injection Order 7/23/200 1 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 Fonnation in the Aurora Pool area. The C-4A and C-4B sub-intervals are separated by an intra-fonnational 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 Unconfonnity. 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 ïí4û () ,-) Aurora Pool Rules and Area Injection Order 7/23/200 1 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-lOO, S-10l, 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 it. 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. 8í40 () 6.,) Aurora Pool Rules and Area Injection Order 7/23/200 1 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 (RFf) 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 RFf 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 Unconfonnities. These unconformities merge at the southeastern limit of the field. The boundary of the Aurora P A, including the Expansion Areas, is within the proposed boundary of the Aurora Pool. Exhibits I-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 7/231200 I 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-I 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-I 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 II-6 shows a cross plot of porosity vs permeability. 10/40 () ) \, Aurora Pool Rules and Area Injection Order 7/23/200 1 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-I. 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 RFf 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 RFf downhole samples~ The reservoir pressure was 3433 psia at 6700 feet tvdss (datum). The API gravity was 29.10 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 ( 4..,) Aurora Pool Rules and Area Injection Order 7/23/200 I viscosity was 0.722 centipoise at reservoir pressure and temperature. The bubble point for Aurora crude varied according to the sampling method. RFf 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 II-2 shows a summary of the fluid propertîes for the Aurora accumulation. Exhibit n-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 GOe. 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 2,700 mmscfd gas. A GOe pick was not clearly defined, but based on interpreted wireline log and test data the GOe 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 owe is interpreted at 6835 feet tvdss from sidewall core data and logs. 1 L/4U () ~ Aurora Pool Rules and Area Injection Order 7/23/2001 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 owe 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 RFf 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 RFf data were collected. The entire Kuparuk interval was oil bearing and no gas or water contact was detected. The RFf 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 RFf 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 API 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 GOe in the toe of the well at ~6680 feet ~",,"\',~.r'\ 1":>/ '+V <) .) Aurora Pool Rules and Area Injection Order 7/23/200 1 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 December2000 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 RFf 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 RFf 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 Developme'nt 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-I 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, RFf, 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 II-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 7/23/200 I 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 II-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-10l, 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-10 1 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 7/23/200 1 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 waterftood 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 (UU) -.,) ; Aurora Pool Rules and Area Injection Order 7/23/200 1 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. 18/4ù ! ,I ~) ,i.,/ ~) Aurora Pool Rules and Area Injection Order 7/23/200 1 III. Facilities General Overview Aurora wells will be drilled from an existing IP A drill site, S-Pad, and will utilize existing IP A pad facilities and pipelines to produce Aurora reservoir fluids to Gathering Center 2 (GC2) for processing and shipment to Pump Station No.1 (PS 1). Aurora fluids will be commingled with IP A fluids on the surface at S-Pad to maximize use of existing IP A 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. IP A 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 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 IP A 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 r~~ 1 ~ " Aurora Pool Rules and Area Injection Order 7/23/200 1 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 C'-) L I Aurora Pool Rules and Area Injection Order 7/23/200 I 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 r) ~) i Tr Aurora Pool Rules and Area Injection Order 7/23/200 1 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 devèlopment 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-pre venter 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 5-112 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. 2S/40 ~~) ') ~, ,J Aurora Pool Rules and Area Injection Order 7/23/200 1 The following table indicates casing and tubing sizes for proposed Aurora well designs. Surface Inter 1 Prod Casing Production Production Casing Liner Tubing Vertical 12-114" to 7" 9-5/8" to 4-112" 5-112" to 2-7/8" 5-1/2" to 2-3/8" Horizontal 12-114" to 7" 9-5/8" to 4-112" 5-112" to 2-7/8" 5-112" 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/lMoly, or with L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/lMoly, 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 N-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 IP A 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-10 Ii 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 -»~""""'~"} 1..) t ,1 Aurora Pool Rules and Area Injection Order 7/23/2001 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 1-2. In the S-100, S-lOli and S-102 Phase I development wells, LWDIMWD 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. L WD will include GRlResistivity 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 6-118" horizontal section. After drilling the 6-118" horizontal hole, a 4-112" slotted or solid liner will be run, cemented and perforated as necessary Subsurface Safety Valves There is no requirement for subsurface safety valves (SSSV s) 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 ! " () 6r) Aurora Pool Rules and Area Injection Order 7/23/200 1 from its scope. \ 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 KClmud 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-20a 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. '¿ó/4U ~,) ) '-'I Aurora Pool Rules and Area Injection Order 7/23/200 1 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 7/23/200 1 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-200l. 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-200l. 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 /" I' () ~) Aurora Pool Rules and Area Injection Order 7/23/200 1 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 250402 (Enhanced Recovery Operations) and 20 AAC 250460 (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 250402(c). Plat of Project Area 20 AAC 250402(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 250402(c)(2) and 20 AAC 250402(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 250402(c)(3), Exhibit V-I 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 250402(c)(4) Development plans for the Aurora Oil Pool are described in Section II of this application. 29i4û r " () " Aurora Pool Rules and Area Injection Order 7/23/2001 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-10 land 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-lOl well and the S-104i well respectively. A cement bond log indicates good cemenCbond 'acro'Ss and above the Kuparuk River Formation in ..,.; S-104i; whereas further logging will be necessary to confirm cement integrity in S-l 0 1. Conversion of the S-lO 1 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 7/23/200 1 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 8-104i '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. lllitic 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% KCI 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 . I " ( ~J Aurora Pool Rules and Area Injection Order 7/23/200 I 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'Enharíced 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 on 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 . I " ~) . ) ~ Aurora Pool Rules and Area Injection Order 7/23/200 I 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 5-101 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 MiluveachlKingak 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 " L) ) '- Aurora Pool Rules and Area Injection Order Hydrocarbon Recovery 20 AAC 25.402( c)( 14) 7/23/200 I 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 ,L " ~) -.,) Aurora Pool Rules and Area Injection Order 7/231200 I 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 TIIN-RI2E: Sec 3: N1/2 TI2N-RI2E: Sec 17: S1/2; Sec 18: SE1/4; Sec 19: E1I2; Sec 20: All; Sec 21: All; Sec 22: W1/2NW1/4,S 1/2; Sec 23: SW1I4; Sec 25: SW1I4; Sec 26 - 28: All; Sec 29: N1I2,SE1/4; Sec 32: El/2; Sec 33 - 35: All; Sec 36: Nl/2,SWl/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 7/23/200 I (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. "it-. 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 not promote waste, jeopardize correlative rights, and is based on sound engineering principles. "',. IAA JV/"'T'V " ..' () '-') Aurora Pool Rules and Area Injection Order 7/23/200 1 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 IT fluids for enhanced oil recovery in the Aurora Pool and consider the following rules to govern such activity: Affected Area: T11N-R12E: See 3: N1/2 T12N-R12E: See 17: S1/2; See 18: SE1/4; See 19: E1/2; See 20: All; See 21: All; See 22: W1/2NW1/4,SI/2; Sec 23: SWl/4; Sec 25: SW1/4; Sec 26 - 28: All; Sec 29: Nl/2,SE1/4; Sec 32: E1/2; Sec 33- 35: All; Sec 36: N1/2,SW1/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids appropriat~ for enhanced oil recovery ma)kbe 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 PBUV-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 7/23/200 I 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). '" 0 !,~" JO/'-tV , I .,1 Aurora Pool Rules and Area Ù1jection Order 7/23/200 1 C) -.) IX. List of Exhibits 1-1 1-2 1-3 1-4 1-5 1-6 1-7 1-8 1-9 Aurora Pool Location Map Top Structure Map Aurora Participating Area (AP A) Type Log for Aurora Pool Aurora Areas Structural Cross Section Dip Seismic Cross Section Strike Seismic Cross Section Fluid Contacts 1-10 Net C4/C3B Sand Map 1-11 Net C3A/C1 Sand Map 1-12 Net A Sand Map 1-13 Net Hydrocarbon Pore Foot Map II-I Model Layering and Properties II-2 Aurora Fluid Properties II-3 PVT Properties II-4 Production and Recovery Profiles for Primary Depletion II-5 Production and Recovery Profiles for Water Injection II-6 Porosity vs Permeability III-1 Aurora Well Tie-ins - Northern S-Pad III- 2 Aurora Facility Location IV-1 IV-2 IV-3 IV-4 V-I Typical Vertical Completion Typical Horizontal Completion Schrader-Kuparuk Injection Well Aurora and GC2 Water Properties Affidavit VI-l Borealis NOPF C4B Sands VI-2 Borealis NOPF C4A/C3B Sands VI-3 Borealis NOPF C3A Sands 39/40 " , ') L, Aurora Pool Rules and Area Injection Order VI-4 VI-S VI-6 VI-7 VI-8 Borealis NOPF C 1 Sands Borealis NOPF AS Sands Aurora and Borealis C-Sand RFf Data API Gravity and GOR for V-lOa and V-200 API Gravity ~ 7/23/200 I VI-9 Interpreted Fluid Contacts in the Borealis Region VII-1 Draft: Prudhoe Bay Unit Western Satellite Production Metering Plan .~" r '! ". '-tv, "'1" V .. Exhibit 1-1: Aurora Pool Location Map SANDPIPER UNIT , i.. L_, MILblJ;~ POINT UNIT ~ COLVILlE RIVER UNIT ,.J - f- - ì:~ ~--y - -r'(:.-c"", ~.. . . - -' . ~°.RTHSTAR UNIT r .r .f¡~~~'-,'~f$ G' ,/Jc"....\~f._,,/;:::t.~<'~~""'- I ~ -1 L' , .I;;:,., -', -J f t=:'..r-, ./;; ~ ~, ---~ \ '-"'....., -, -.-...., '-"""~, {-')Cjf"-" -j - J". í;~~~//' , ~ ~ (. 1- -: 1 ;)"'~~\ ,~~i "\ r'~~-. i L";~' ':;l<~~~,~_r':- ~~C,~LANDUNIT . -¿. I " . ~ ~ /:~;(iAl~'). . ~ . '''1, l 1. AURORA POOL {"" // f~.r..d"";:o, ::~" Ji . ) '- w J - -' r - r- l J '-_.~' ,f '~:" ff~;~¿j:. )i:¡ - ~_. r- J-_r- -L,ì.._- {_I# j~¿\ . . f . . i~ l~.( ,,,,:,,~._-,..... ~r...... ~ .---- ~ .. I ~ "._r't~"~i~"'''''~- f r -...J KUPARUK RIVER UNIT PRUDHOE BAY ~~ . - ., ..J . '1 l~J " "~ ,.,. to 5 10 15 Miles ~_~~._4- ._~----_.- ._J~..,-..~:.....- ._-~_._~..~ .__.-.~._--~ --.._J BPXA Cartoaraohv/4--12-2001I1m14369.dan .' ~ . ( ~J Exhibit 1-2: Top Structure Map ~ ~ æ 6111.81i18 _. ,I( -"'- U fIU88-. lIZiIIt FEET~fEET STATUTE MILES~' STATUTE MILES Au rora Field Top C Sand Depth Map C.I. = 25 ft L. -..- I I ...- I I { , . ' '\ 1..<1 EXHmIT 1..3 AURORA PARTICIPATING AREA (APA) ADL!28254 i I 1 \ ¡ I í ¡ ..." '-.., '. ' ¡V-''''.,''''........, ,- """1-" . I I t ! r18 _! - J.7 - - I I I ¡ AD~ 28255 I ;-----------_.'1--'- ¡ -'----_.'-- . I ,--- -., ¡ 1 I 1 , 19 \ 20 I ! I Expansion I Exp 1 I Area 4 Area 3 ¡"'~It".....,.J,I>'A,..;w:"" ' .,-"'.' '-"'..¡., ..,,_.-I.} 1 I I j , 1 10 I 29 I ~ - -\ - -1- ~ I ¡ ADY 28259 1 .....-,--------._----------1--'-- I '--'-'._--- ,- , 1 Expansion ~ \ I Area2 , \ ~ æ I \ I ¡ ~.., ."", ..~~~ n-.-._J -...-" - --' .. ! ! ¡ ! <f ¡ 0 ! , ADJ47450 ~ i 1------r------- , \ I ¡ I j I I i ¡ ~ .., ¿ i t. ADL\28253 ADLI385193 ! \ I' ¡ ! ¡ ( .......... ~-.r ~ WI>.m'I;It \ ¡ \ ' \ II 15 ~ \ I ~ \ AD~28256 ---~ II' i PBU BOrndary J I 22 , 23 I , I I ,--- \-.. . -~I I,~--+ I ~ ¡ i 28 ! 27 1 26 25 ~ I APA! - -I I AD~ 28258 I ADL 28257 1 ------'1--"'.'----"'-----_._-_._-'---'-- ------.---1 \ Expansion T12N-R12E I I \ Area 1 ! 34 35 ! \ ! I "lilt' ~r".....-L. - 16 ~ 4 36 ~ r - ~ .~.. _J - I ' \T11N-R12E i I . ! t 2 I t \ 1 . , ! ! , i ¡ ~ i . I ! A?LI28261_--!---~~f826~_-1- I I i ~ I I \ i ! I 3 1ft:) - 8£:> ~ ~ VI>:) . L£6l""..6lOOS #TdV OOZ-A ß~A\JO UO~ 'fI\Mdn)f Iood tUorov JOj 2iO'l 00,.<1. :t-I t!Q!lJX3 ') <::> ..... 8 ~ ~ ..... '" ..... 8 ~ § ;¡: I I G: ~ > I!J ¡:¡ , I , r) ( ') Exhibit 1-5: Aurora Areas I 881181... . I 885,'" I 81~ , 8tl'. I , 1S2I,'" .., 825,,,,, I I 8S8.8.11 l I:, f---~", 1 :: j i I (I , { , ~, , : :! , 1,1 -- 'I I I ~ _-1_------J-__~,I____~_---~~--~t--, ~I . ------y- --- -- I J.: !'" ~. ~~ 1 --,I': I I ~ ¡ L. -- 1 1\ I I I ~ I I ~I '- I 1 -----\ - r ~ ~ l \ j I I i I I 1 1 ,. - 1 -------,-- I CII I -Ì , i , . I , I - ~ ,f , , ~ ~-----~t--- ~ 1 II I I I I I 4 I 1 1 III J_____--L--- ~ : I 1 , 1 , : : " I. } I ì ~ /' 1 I I I .JÞ" l I I --' III -I- -.. -- I .1 _.1_----'\ '1__--:,", ~l-------T-- -- 1 r-I II I 1 I 1 I 1 , 'I' -1 : I ~/I: I r _l... , .S!'I' 811.1~ 81S.HI , III L. ! -;. I 1 \: --i- 1 1 1 ( I , II BeeCh~~\, Block , - , ---- -.- r III L i - , , Eastern, ¿ Block -, \ , , CII .J i 1 1 I - --~~ ~ .",.,-, '. " ' ~ '" . i )/1 I I 825.11' , I I - 8B. 8.1 I'~ "T_~PEI!T ITIIMI .1LU~'1T1nUTE MILD .. Aurwa field ..... Yap T°r....~k . ---... ~...... ~ ' --- I I I I T <f~tjJ , ",' .., - --- /',~"{,',:,, i ,', i,.,:,',.,(, J~p ',' ,--, ./ J:I ~~~~~t:~;i~~~q~~t~ \ ~....,' '~'~"1':" .E :-c~~:':""'~'1 I](-~~}}' (' " ¡~fV'~- \\-~\ 'jY' ,-'- ~~_1~'¡ .' ~' '\:I~' \ '\ 'J' . '~',' '~1\~'~" '~' , ' -:~:~A~_:=:;~,~nl,." !~.ll"" ' ~" '",uy!,r........~~"-",;2l,¡c..:.':.~!!:!!--~~5:&::'Y~..J..--c--- ~~:!~:~,:.'~:::t71~:-7~~~1;,,~1f~i_:~~-:.:: -\': ~ ~:~. ~,~~~-"",""" ... ' " ',\' Òi:g',j' .,~"~- '. ..~'--1-~-- l_l/I,Ij~ ',' , ., ------ -.' i 7 ~/](.", . ...,_...,.....,~._~..~,~~-~~ ,~;~~~~~ ,'\ ',' ,"r" '..:'.~7::.";~-'::~:':~;::::';:~~~ ~,_:",L. .,-""I""':"'~"~ . -¡" ....;:'~.:.:..~, ~'I"".r~~;'~~~~~-+'~~ fÕO ~'. ~- ~'~¡.'l-~~'=~E :. ",", ",,', c"jJ)~ '.. ~ ~...~~/t.:""""""",",.,,..,..'"It_~ÞP"'.' : ( ! ' .. ~'.'::'F,~:-:'~~'::f~~~~ :,;;"\~-'~~~~I.~' 'J, ' , .,", r~ilr-i1f' '- ". !--rr' l¡i~ },:,',',J", ' ,,-> , 1/", " 'I . .. ¡ - ~::~~~~::~:;-::,,~;~:::,~~~,,'~',.;:.:,~c,:'::~V: ,,'~~. ~:, ,-~*".:...,:+J._-:,-- !:";":;~r'¡'.":p.r>,r-,~'~~~~T~¿,:~~::' ,'.,:-~',~',,~J:.., crr' ¡- -- III ~ tfj >< =r ~. r::r ~. f""+ ~ I 0\ . . en ~ c: 0 f""+ ~ I-t ~ ¡-...¿ n ÞOO-1 0 00 00 rJ). (D 0 f""+ ~. 0 =:; , . ~ t . ' A () () Exhibit 1-7: Dip Seismic Section Beechey Pt #1 V-200 A' 8-03 8-16 8-14 M-13 NW Sag River ~~_i , ' B (. ~) Exhibit 1-8: Strike Seismic Section 5-101 S W B' Schrader Bluff ":'aø~'< Kuparuk .1,'°(" ..' Sag River ,I () ( Contact Beechey Block V -200 Block Crestal Block GOC 6678' tvdss Per (Beechey Pt St #1) Beechey Block WOC Exhibit 1-9: Fluid Contacts 6835' tvdss (Beechey Pt St #2) 6824' tvdss (V - 200) 6631' tvdss (S-16) 6812' tvdss (N Kup 26-12-12) r , . ' ( ( Exhibit 1-10: Net C4/C3B Sand Map 8".888 ... ~ILEEN- ~ L . i III 8851888 81'.1888 i\- 8211888 -CS) ,N 881!" 885~'" _. --... p8t. I '1 {!)- J PIIT~PD1 ITII1UfIIIIUI~.1tImI1t ma AURORA FIELD KUPARUK C4+C38 NET SAND HAPS " ¡ I () () Exhibit 1-11: Net C3A/Cl Sand Map ~ .. ~ , ! ..lul , I I 8Ahase I I sa}.. ell.. -., ..... ... U~ ra;r~ra1 ITRTU1'! IIIL!S ~'1111'181! IIJLIS AURORA FIELD KUPARUK C3A+Cl NET SAND MAPS '- I a. I . I " () () Exhibit 1-12: Net A Sand Map .. EILEE~:.r i J 8851'" II 818,,- '~8;5'188I I , 821,8" 1 I" 825,. I I 831.:, i_81 I I' 1 I, I.. ." I 1 I I ~ I~ 1 1 , I "i 1 I I I 1 1 - ! ,J .t ~----L-------l---__~l-- -------¡------- ,---- --I --, 1 1 -"'l, L:. :t\' ~'/: : )' 1 :1 : "j I I 1 .. ill I I I I 1 ~ I I 1 I -______1 ~------ I '/ _____1 PBU BO~ndary 1 III 1 I:Y I I 1 III L I BEECHr" ,_PT_51 _2 I 1 I -Ì ill. 1 'I /: .. I I I 1 I, . 1 BEECHEY_PT,ST_1 I 1 1 .....(fJ ,~ . ~ r r-~02 ~ PA ÞOU~d --- : --- . ---T-------1-------lr-:>-~~=~r--- 1 ~ ~ : : !oo tlKdP:.Ø-12-~, I -f I , 1 5-03 '_.,~ J ; I -f ! ! Q ~ - }__~~X-24 ,~, r------- :(- ~-------r-------~1-- þ-1011fA.s ~~or:t J :r--j ! I 1 I' , . 5-17 =-e 1 -Jb I! I I I. r 1 : 1 1 1 J 8 - s-. 5-13 ~ 1 I , -02 -/1,! 1 - ----- : --- I ------ --~~~0-:r¡- w-13-1t? ~ . J~:, ; "'-9 ~ 1 . 1 \- , ~ 1 +-------- ~ ~ III : / \ ~ 1 I : I J I One Wells r ,- I I 1- J I 825.188 831..' _. - , ....... ... ...- \, '~---- I I I I U~ PlEr_~P!I!1 ITItTUIIIIILII ~'1TII1U1'I .JLa AURORA FIELD KUPRRUK A NET SAND HAPS . f . r l.) l,) Exhibit 1-13: Net Hydrocarbon PorePoot Map \II , ~ILEE~:.r i' illS,'" " 8J'.,- , 6\1,5",. I , &21,'.. I, 825,- I I 638',:. i. 1 I 1 I 1 1 = =-1 I I , , \ --:" I I I I , \ I I 1 I I 1 " I I I I I - ~ --J-------~--------~-------~------ t-- ------- I ----- I I I ~ 'k ~~ I ~ ~ } I ¡,,- ~ ¡LY I I I I I .:..J ¡ I ,1 I I ¡ I I I I I I PBU BO~ndary ¡ I 1 I I -Í , I i I I. 1 1 PA ~8oundary } , -------,-- iii --- T-. I VI L I I -Ì . 1 ' ;. ., \ 1 I I 1 I -t 1 ~ I , --4-~ ~-------+----- I en ~ I I ' 1 ~ , , ", '. l-t : i -- - - -- - ~ -- -- - - ~ ,C,"~ ,,~;~;'~-' ~2~;~=¡:i~ :~ i- ~tf~ !:î I 1 ' :', 5-18 , . ~n 1). ~ II " . I :m. == I I I I t.f iJ I I I , 1£ WE d ''''-9 \ ì ~/ , I -. I 1 ' . 1- , ...JÞ" , I , . ,- I 111.1- -- -- I ----..1--------'----- --.I- -----+-------., VI ÏD l-------T---" I / I ÏD ~ I 1 I" , ,i .~ } , I I I J I . I 1 UP_9_1\1._12 8Ahase One Well,s / , ~I 1 .~ I I ~ I - r 8.1.. r 8I5~" '818.1.. 81S~" I 821}U. '825~" aI.'" \II L . lID lID -., , ....... ... . .. ,..... . "- --- I I J t8~ PlEr~PEl1 ITIMe "ILIS~'snmm .ILII AURORA fIELD TOTAL KUPRRUK HPF HAP ! . . . ~) ~) Exhibit 11-1: Model Layering and Properties A verage Properties by Simulation Layer Layer Zone Porosity Permeability 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 11-2: Aurora Fluid Properties ~) '1-].1)0 Pv-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 (B g) 3433 psia 3433 psia 150° F 25° - 30° API - .kr¡¡..tVClwu'YoJ~ 0.722 cp 0.45 cp 0.022 cp 717 SCF/STB 1.345 RBUSTB 1.03 RBUSTB 0.843 RBL/MSCF , . . ~) ~) " <- Iv i5D Ma.... Exhibit 11-3: PVT Properties Pressure So Oil Gas Solution _~_N^wf~,~,~,w,~,www~Ëw~~_"!~^-, ,'~ R~!!!!~~w,~!~~~~~!¥.", ~~!!~,~~~!y~ ,.~^,ww§2w~_"^ cp cp scUSTB 3464 1.345 0.722 717 3100 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 .210 1.554 1.100 0.016 375 1350 1.185 1.987 1.280 0.015 309 1000 1.159 2.732 1 0.014 244 650 1.133 4.283 1.880 0.013 177 '''W,',v.w".W.,W.WIWMWWM'''''''Wh'.'WN,',.., WNNW.w<v.W'...W^'W"WWWNW.W^W^~M''''VNNo"NM",W'.'^'^W^.........."",.'''''''''M """"',WhW,",'WW'NMWN.''''''''''''=''""W,,,,,,,,,,, "",w,wu",'^w=w.w.'.w.v.w/W.WN-'^,~N.' """""""'.w.'..........WN,''''''''''''''''oYNN'',WN'''''','''' 300 1.102 9.340 2.440 0.012 105 124 1.081 21.615 2.950 0.011 61 ""'''''''''''''''W''''''''''''''''W''''''''N'...................'"",-",w"",,,,,,,,,,,,,,,,,,,,,,,,,,,',W'W''''.w..........'',,,,,,,,,,,,,,,,,,,,,,"""v. ,','.W.........W-.V"V.O,WW/'NN/'NOM""''NN,Y,Y.W. ,""NW."ow...V"".',WN^,",",""^"''''''''''''''''''''W'''''''', ,"'''W''''''.W''^'.~WNW.y.y,W^W.W'.VoYNM .W.WW.W.VN,'....N'.'.r.<MWN.W""""""W....W... 0 1.041 4.520 0 B ~ ~ .-. Õ 30,000 - 25,000 - ,-,. ~ ~ 20,000 ~ 8 -- B 15,000- ~ ~ 10,000- 5,000 - Exhibit 11-4: Production and Recovery Profiles for Primary Depletion Oil Production ""'stbd --- scflstb 2000 2005 2010 2015 2020 2025 2030 Year Gas Production 2000 2005 2010 2015 2020 Year 20,000 - 18,000 - 16,000 - 14,000 - 12,000 0:: - 10,000 g - 8,000 6,000 4,000 2,000 2025 2030 Water Production 900 800 - -- 700 - ;g £ 600 - ';;' 500 "' «i ~ 400 - I-< ~ 300 - ~ 200 - 100 - , 2000 2005 2010 10,000 9,000 - \ 8,000 - 7,000 -. 6,000 - ' 5,000 - 4,000 - 3,000 2,000 1,000 14 . 12 - ~ 10- '-" ~ 8- 6 g 6- ~ = 4- 0 2- 0 2000 2005 2010 2015 Year Oil Recovery 2015 Year 2020 2020 2025 2025 -~ f' 2030 ,.... 2030 Exhibit 11-5: Production and Recovery Profiles for Water Injection Oil Production 12,000 1,800 ..... stbd 10,000 - - scflstb - 1,500 8,000 - - 1,200 ~ ø:: ~ 6,000 - - 900 0 - 0 Õ 4,000 600 2,000 300 2000 2005 2010 2015 2020 2025 2030 25,000 --. 20,000 - œ u 8 15,000 - ......., ~ ~ 10,000- ~ 0 5,000 - Gas Production T 2000 2010 2005 Year 2015 Year 2020 2030 2025 ,< Water Production 4,000 3,500 - ~ 3,000 - .J::J e, 2,500 - ~ 2000 - ~ ' t 1,500- "æ ~ 1,000 - 500 - ,. 2000 2005 2010 2015 2020 2025 2030 Year Oil Recovery 40 35 - ~ 30- ......., ~ 25- () ð 20- g ~ 15- - Õ 10- 5 - 0 2000 ,.. ",-,,' 2005 2010 2015 Year 2020 2025 2030 Exhibit 111-1 Aurora Well Tie-ins - Northern S-Pad TolFrom Module 57 S-216 S-lOO S-44 S-200 S-213 S-103 S-106 S-105 . .8oeoooosi8s-02OOOOOOO888088 S-201 S-104 I s.tine . WI Booster Pump (If necessary) TolFrom Module 93 8 Polaris Well 8 Aurora Well 8 IPA Well 0 Potential Well Productionffest Gas Lift Piping .. N~ ",.. ~.,/ Production Trunk Gas Lift Trunk Test Trunk Water Injection Trunk ~ Water Inj . . . I &. c. Exhibit 111-2: Aurora Facility Location Production (#) Test (#) Gas Lift (#) Water (#) MI (#) Future Equipment (#) . Aurora Well . Existing Polaris Well r3 . IPA Well , # - Surface Sat~_lIite ~9uipfT1_ent Water Injection Booster Pumps & Skids (If necessary) Injection Water Line Tie-in (lP A injection weD) . r . I ~ ~ Exhibit IV -1: Typical Vertical Completion X-nipple @2000' X nipple (ID=3.813") XN nipple w/NoGo j ::J C -' ..J. ...J ~ ---:?£..~U~~_.. :J't: Conductor Casing I 80 MD ~ 20" casing Surface Casing 4355' MD 3285' ssTVD < 12-1/4 hole or 7-5/8 casing Tubing 4-1/2 or 3-1/2" Cr-80 Tbg 3 GLM's Production Pkr. 6600' ssTVD . . ~p~~.ë ~.d. ¡;ris. - . . - . . - . . - . . - Kuparuk A sand perfs Production Casing 6900'sstvd < 9-7/8" hole 7 or 5-1/2 " casing I . 1:) . . ( Exhibit IV-2: Typical Horizontal Completion j ::J [ X-nipple @ 2000' _I 55° tangent thru HRZ !~¡t I ~;i;" !~} ..J .J. ?i~ ì Conductor Casing I 80MD ~ 20" casing Surface Casing 4355'MD 3285'ssTVD 13 1/2 hole 10-3/4 or 9-5/8 casing Tubing 4-112 or 3-1/2 " Cr-80 Tbg 3 GLM's ::;=:::") t-: c ~:=:~18's>rVD T~'K~:~~:::"~"'~';'_"''''''~~~''''''''''=':''''''''':''':''C''''''-:''':'";':;""';"""'''''''''.. 10400'MD 6678'sstvd ' , ':" 9 7/8 hole 7 or 5-1/2" casing Production Liner 11852'MD 6700-6712'sstvd 6 3/4 hole ,~~Y~..?~..!..:.V~u:;,,,. c~~~~, -' ,,~7':".':':~.4I"". -,~, TREE = 4-1/8" 5M WËÍ-LHEAÖ"; FMC 11" ~AëñJÄTÕR;~^'^~"-~"V"WV_~--_w_" l<s:"E[ï3Î";'w"""",w,.w"", """'''''''S4~5' 'EfF~vELÐ7~"v,-,,,,,,,,,,,,w, "''''''''''''3'5':'9' w.vNMM''''''^'-'.~'HM'A,.,,,,~,,',.ww.'M1,~'''''''<'NM'''''^''W'N''''''''''''''^'''''''''''''''''''W'H^W KOP = 300' "Max"AngÎe";;",m,v""'S4"@2200 '5ãiümMri;;w~v."~'~N~.wmvw,w'ã79ã' "ÕatuïñÏŸ'[j;;"...."m"""""'S7Õõ""ŠS' &,':EXhibit IV-3: Schrader-Kupac. )jection Well 8-104i SAFElY NOTES: ACTUAL DEPTHS WILL BE PROV IDED BEFORE COMPLETION 9-5/8" 40# L-80 BTC 37361 ~ I I 124031 1 X-Nipple, 3.813" ID I STA MD TVD DEV 1YPEMAN LATCH ~ GLMS 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 L SLSV 7175 5268 30 Baker CMU BK GLM1 7266 5347 30 KBG-2-T/L BK SLSV 7333 5406 30 Baker CMU BK Minimum ID = 3.725" @ XN nipple I I I 168421 ~ ~i 168531 0 :8: 170611 0 :8: :8: --t 72011 L. 0 0 I 4-1/2" 12.6#/ft L-80 I NSCT :8: Z --186791 1 4-1/2" X, 3.813" ID 1 1 Baker S-3, 7" x 4.5" 1 1 Baker SABL-3 1 Baker SABL-3 1 Baker SABL-3 ÆRFORA TION SUMMARY REF LOG: Ref Platform Express GRlRes 1/27/2001 ANGLEAfTOP~:~1 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 f 1. 187031 187241 187361 I 4-1/2" X, 3.813" ID 1 J 4-1/2" XN, 3.725" ID 1 1 4-1/2" WLEG 1 PBTD 1 I 7" 26# L-80 m-BTC 1 1 91001 1 I 91861 I ~ DA TE REV BY COMMENTS 01/08/01 P. Smth Original Proposed Coll'1'letion 02/09/01 P. Smth As-Coll'1'leted PRUDHOE BAY UNIT 1 AURORA FIB..D WB..L: S-104i PERMIT No: 200-196 API No: 50-029-22988-00 Sec. 35, T12N, R12E, 4494' FEL, 633' FNL BP Exploration (Alas ka) <1WÆlRÄIE 11m Exhibit IV-4: Aurora and GC2 Water Properties Source, ppm 8-105 "C" sand water 4/01 GC2 Produced Water 22: 2. 17 ~ 1960; 1640'" , ~ ., - - 53! 247~ 12600 ~ 4.32 f . . m'O , 14 ' 156 ~: , ~, ' -" -- .. - ,~. 6.67. 6.9~ '. -" , . 82, 107'" 9020, 8080~~, -. .." -' . ".-= . . 41 26.2 . - . . A_".. .', . .- -. ~ 38: 560:: 21,932 " 23,427 . I ~) . I Exhibit V-I AFFIDA VIT 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' /0 ( , 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: 6/~,Äí /-;»~ G/~-"../ Gordon Pospisil Declared and affirmed before me this ~ day of ,\\\\\"""III/.I ~, .... G I i ,..~ ~",..... r.::......,,-~,¿ð~ ~ ,",-..' '~T:. ~ ~i~OT"'A .~ ::: : <IIIIiii;"" 7.(. ~ - -: -1- : = = : J - ::: ~.-o CI:::: ~*\ ~8' ~ fA..;S ~ ..A ". .. .o-w S ~ ¥"~ .. .'... ~ ~'" 4f~"..",..:,;:,,,~ ~ '/¡jCf OF A\,.r..~ III'IIII"\\\~" :fU1JÆ .)Oðl . ~ ¿11- ÚW~. Not~ubliVn and for Alaska I I My commissIon expires: f /IY/¡§ ~ ,,' . J ~) ~) 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 wcll tcsts 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 . .,J Exhibit VII-! Ll Prudhoe Bay Unit Western Satellitflrr¿uction Metering Plan BP Alaska, Inc. Post Office Box 196612 Anchorage, Alaska 99519 July 23, 2001 Jack Hartz Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 Mike Kotowski Division of Oil & Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, AK 99501 Dan E. Dickinson Oil & Gas Tax Division Department of Revenue 550 W 7th Avenue, Suite 500 Anchorage, AK 99501 Re: Prudhoe Bay Unit Western Satellite Production Metering Plan Gentlemen: BP Exploration (Alaska) Inc., as PBU Operator, requests concurrence with the Western Satellite production metering plan presented and outlined below. Initially, this plan would be used for production from Aurora, potentially ten (10) to fifteen (15) wells. Application of this metering plan to other satellite fields is anticipated and would be the subject of future satellite speêific discussions with the State. PBU Western Satellite Production Metering Plan Objective I The PBU Western Satellite production metering plan is designed to: accurately meter and allocate Satellite production; maximize use of existing PBU facility infrastructure and allocation processes where appropriate; use best practice learnings from WOA and EOA experience to implement specific improvements to the current well testing and production allocation process; and promote operational efficiency by handling Satellite and ¡PA wells consistently. Key Provisions 1) The WOA flowing well allocation technique will continue as currently implemented. Daily production from flowing wells will be based on the flowing tubing pressure and a modified Vogel curve, or equivalent, developed from well tests. 2) The EOA technique for allocating gas-lifted wells will be adopted to replace the current WOA procedure. Daily production from gas-lifted wells will be based on empirical well performance curves derived from 3-phase flow equations and production well test data, and will be a function of flowing tubing pressure and gas-lift rate. 3) A minimum of one well test per month will be performed on each well. Efforts will be directed towards increasing the availability of the well test separators through improved analysis of well stability test data. 4) All wells flowing to a gathering center (GC) will use the GC's well allocation factor for oil, gas, and water. Improvements to the GC bank meters are in prbgress as part of the oil gathering system leak detection process which should help improve allocation factors. 5) All oil and water flow meters on well test separators and the test bank at GC2 will be upgraded to Micromotion meters. Use of these meters should improve both gross fluid rate and water-cut measurement over that obtained with vortex meters and capacitance probes. DRAFT - .' . ( ~) 6) Zero-rate tests will be performed on all WOA pads and gathering center test banks once a quarter. If leak rates are not within acceptable tolerances corrective measures will be taken. Leak rates from the zero-rate test will be used to improve test rates if necessary to obtain more accurate allocations. 7) Reservoir specific shrinkage factors will be used to correct metered fluids to stock tank barrels. Recommendations for Specific Developments Summary The key provisions above will be applied to all WOA IP A wells for the purpose of production allocation, and results will be evaluated based upon the ongoing quality assurance process. Satellite wells will be addressed as described below. No distinction will be made between condensate and black oil for Satellite wells. Any NOLs removed from gas at the COF will be accounted for as IP A fluids. Aurora The first three (3) to six (6) wells drilled at Aurora, will follow the previously proposed Aurora metering plan, namely: 1) Use the existing S-Pad separator and test each well at least twice a month. 2) Prior to Aurora production start, use the APC portable test separator and a zero rate test to evaluate and correct for the performance of the pad test separator and manifold. 3) Use Aurora specific shrinkage factors and single-point allocation with an allocation factor of 1.0. 4) A monthly report will be issued to the State of Alaska. The report will include well test and daily allocation informatioIifor each Aurora welL The Aurora interim metering methodology will continue until the following steps have been accomplished: 1) Implementation of OC bank meter upgrades, and 2) Implementation of IPR curves for all gas-lifted wells at GC2. The Western Satellite metering and allocation methodology set forth in this letter would be used beginning the first day of the month following implementation of the above steps. All gas produced from Aurora will be treated as having been provided to the IP A to meet fuel, flared, and lost gas obligations. Polaris Polaris metering and allocation methodology is expected to follow the PBU Western Satellite methodology, but will be addressed in the application for formation of the Polaris Participating Area. Borealis Borealis metering and allocation methodology is expected to follow the PBU Western Satellite methodology, but will be addressed in the application for formatiðn of the Borealis Participating Area. For clarification, no change in current metering and allocation plans is envisioned for Midnight Sun and OPMA, subject to any specific review that might occur with respect to these fields. DRAFT /' , ,.Þ- '~ ...) Please find attached a copy of the presentation slides. Gil Beuhler, PBU Central New Developments Team Leader for BP Exploration (Alaska) Inc., will act as the single point of contact for the owners with respect to WOA production metering. Gil can be reached at (907) 564-5143 or BeuhlcGG@BP.com. Sincerely, Joe Hurliman GPB Resource Development Manager BP Exploration (Alaska) Inc. Attachments Cc: Rob Dragnich (ExxonMobil) Ken Griffin (Force) Jim Johnson (Phillips Alaska) DRAFT . . =+t:: U'J ::t> '~ e,,) STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION AURORA POOL RULES AND AREA INJECTION ORDER NAME,- AFFILIATION (PLEASE PRINT) ~(Wn Ne1 S-ðr1 t1fÀ/Ý£2J9/et W~ Jeff' ~/'/' (~O r[k, '~ rfbS¡fI,[/( 1- /-f / ¿Î~ r,-~ ßV1A <.J¿ S-~, ~1, ¡J I/W CÇ¡Wv1 y Vt1N :I:Nr~.@/ /X(~re< w'£1 \.. If'^ " O()N(-~ tæ4Ni:; e.AS~Vf#J ,-T~ ~OCYl~ ~ C:S°f<-v<-- ~V;.e.b M C/t;;¡JGI/ JULY 24.. 2001 9:00 AM ADDRESS/PHONE NUMBER PNA E~RJn /tA-ó!0¡ { &'¥Ø? ~¡~. ~/ /If (f~ ßP (/;)° ~.."\\\.~ MtkÎ fP f?P pf}î .4:0«'_L /lôcf¿¿ a Lff!s¡ 3G ~~ 5& t.f,- ?;.:=f- -ì ?, .sbty'-Jç // S6 Y'-S7 6 f ÇÓYr:)fJLS ~ f::, LJ - SO 9 :) st t/"- ~3?J ~ 2G2; - ,(Ò~; 7t1-3 -/J-¿R 4;4- Ši54 ~ty- 51'11 2- 6 )' -,-qfJ/ . -¡Ct 8> -/'2:2 {. /78 --f.:z2ð . . . . ::t:t:: Ut " ) 6., ,) ,,~ospisil, Gordon To: Subject: pospisil FW: Aurora Pool Rules and Area Injection Application n::I,,~, ',',: -= 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. 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) inje¿tors. 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 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. 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. 1 &) ciosed as exhibit in 7 1~III'll submission. Additional information should be ready to support a finding that urora 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 8-105 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 recovéry? Reservoir studies were completed to assess the impacts of primary production prior to waterflood startup in the Aurora Oil Pool. A history matçhed 3 phase, 3 dimensional reservoir simulator was used to evaluate changes in predi~ted 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 failúre occurs on a MI well it should be 81 and secured as soon as possible. Corrected in 7/24/01 submission. 2 =+1:: .þ. " STATE OF ALASKA ADVERTISING ORDER tr) . / NOTICE TO PUBLISHER INV E MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. AO-0211427 F AOGCC R 333 W 7th Ave, Ste 100 0 Anchorage, AK. 99501 M AGENCY CONTACT DATE OF A.O. Jody Colombie PHONE June 21, 2001 PCN ~ Anchorage Daily News POBox 149001 Anchorage, AK. 99514 (907) 793 -1 ?? 1 DATES ADVERTISEMENT REQUIRED: June 22, 2001 THE MATERIAL BE1WEEN TIlE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: Type of Advertisement ~ Legal D Display D Classified DOther (Specify) SEE ATTACHED PUBLIC HEARING NOTICE REF TYPE 1 YEN 2 ARD 3 4 NUMBER AOGCC, 333 W. 7th Ave., Suite 100 Anchora~e, AK 99501 AMOUNT DATE TOTAL OF PAGE 1 OF ALL PAGES$ 2 PAGES COMMENTS 02910 01 CC 02140100 PGM LC ACCT FY NMR FIN AMOUNT sv DIST UQ 73540 2 3 ~ ' REQU~ED BVn 1\ n IJ l . ,('fJ(~A }L.----... .~ ~vr--- ~ 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM ~) Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 ... ':110 ... AD# DATE PO PRICE OTHER OTHER ACCOUNT PER DAY CHARGES, CHARGES #2 930935 06/22/2001 STOF0330 $103.74 $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 langtlage continually as a dailynewspaEer in Anchorage, Alaska, and it is now and dunng all saia time was printed in an office maintained at the aforesaid J?lace of publication of said newspaper. That the annexeâ isa copy of an advertisement as it was pulJlished in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of sald period. That the full amount of the fee charged for the fore~oing publi ion is not. ss of the rate charged private indlviduals. Signed Subscribed and sworn to me before this date: ---------~~~¿--------------- Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska --t;!)~~4Ç£~------- \\\~ \A A I"/"r: l \.\. -"--('t:~, ' . ,., Q~ r ~ \.' ~~.. ..-.' ~ro -:::- '-.: ".. OTA ."L- ,.- ~ ": ~ ~~..~~ "-.... --- .- ~ : ÞIJBL\C ~ -- .cP . -. ~3 ..~ --- ~. ~~ ~~':~OFÞ.~., ~-\' ~ ;:" . . . . , " '\- \' ././././ ~ £xptreS.~\ '\\ J J l} J }) )) n ) \ $0'.00 $0.00 $0.00 $0.00 $0.00 $0.00 I;":":"~" ' , " , , ' ,,:, c" , ' , I, ti~tjS~Rf,l'~~J!F~tI~m,,-~q : ",~STATE.þ'F,,~(¡;4$K4:";: I, Alaska ()jf~it~G!J~,ço~ "'I '~~~~:~i~~t , Rules and At:è.àlilie,c:tlorî' ¡Order, ',..", ,..:' , . . ... -'. .... : '.' '.~ ~ ; :BÞExPlorotio'~~{ÄlØskå)~ i Jnc.<by letfel';i.'(J~dJuÌ'ie: ''lS.200,l;hasopplied ~fDr," laQ,area: Íc~t~flôn:!~,r,~~r" land ~ pooL r~~,s.."iVnØ~r:;,~(r I,AAC' 25.46Q':öm:t:'20AAC, :;~5~520.respecflve.y i .fo : enQble'dé"elo.prneÏ1t ,Øf ¡,:the, ;,A,', '~"ror"ç:'<ti,;,h,r~",'~,o, I,'~' ,~l'ud!:lóe.'~BQV. 'fi'l~r 'on, I.t~ ~ ,,' N.cU::lJj:, S::I'o'P'ff.; Q~ f':;~;:~~.~Ù~"~~uli('~:. ¡,,,,,',t, ,t.e'fI', Pf" ø,t,' ~t ,ør,¡'!i/:.f.,,'J:,t-:,>,~ cJei1'corill~erit " ;'re-, i'~9tfë~ted:,txe . Jor to,~~OÓ:P ~, !~'i';" t' ttvely: ear,,"" : ~?:o'fg.tl". ::t$Y :' I~Winé,:t~ê,p . 'jQ;g òn "'NiåkíS(Ç': 'tne : Ala~ka;Oi'IÍ~' I ~etvät1c)'h -~? 1'~~~g7t~ "(~A~~,:~ . son may" , " " håt'fhe' :t e~ tat i 'i(~ '(%s,Ç:1j ~d;uJe d i.hearing ,b4i;þè1d~1)~"fU¡"g. u,"WrttfiJn:~Wiftr1fíë' ,Çomm issrorl;#.f.i~1ttÓ:~i!JQ ':~ ~:~:¡}m~irig' is 'flat til1'Ìef'ý-:'filed, the 'Commission .,will con'- sider the, Issuance of an , order: withou.t a 'hearing. To learn if the Commis- :SJQI1-~III"ho!Pßt~,J~~ta- ~tl ve ,JJeAr:lfiJ;, p!e.ciSe.'.'call , ;:ZJl::~~~:t,~::¡~ ' diso'};lHtY',íNbo',rrítav; dêed ~r~~~(~&~~:l~', att~~~t~J)j~þftii'~i~; P~~~~ contP.ét~JQl:Iy~ç'O- ,0mþleQf 7,9iJ-;~ 2;2lbef~r.e 'JUIYpr:~,~:~,~:,~:~~ j~:,:q" ,Carritny oechsll.Tavlôr~- Chò~r ' ',/" ~ ." ,::, ';", ,', :, " . pUbús~iù~_?p~<'2001, : GRAND TOTAL $103.74 $0.00 $103.74 ..) NOTICE TO PUBLISHER ..) INI8!rMUST BE IN TRIPLICATE SHOWING ADVERTISING ORDE. CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ~r:':',:~~::~m:2~l~~~.~,~~~; F AOGCC R 333 West 7th Avenue, Suite 100 0 Anchorage, AI( 99501 M STATE OF ALASKA . . ADVERTISING ORDER ¿ Anchorage Daily News POBox 149001 Anchorage, AI( 99514 ADVERTISING ORDER NO. AO-0211427 AGENCY CONTACT Jody Colombie PHONE (907) 793 -1 ')') 1 DATES ADVERTISEMENT REQUIRED: June 22,2001 DATE OF A.O. June') 1, ?001 PCN THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss division. Before me, the undersigned, a notary pUblic this day personally appeared who, being first duly swam, according to law, says that he/she is the of Published at in said division state of and that the' advertisement, 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, Notary public for state of My commission expires )2-901 (Rev. 3/94) ~age 2 and INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITIED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. AO.FRM PUBLISHER 6.,) ..) 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 amimmediately 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. (nM. ,.-OuU. ~ ~~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 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. ' bc~~~ Chair Published June 22,2001 ADN AO# 021 1426 I certify that on //1 .f))/ () / a ~ of the above ~ faxed/mailed to eøch of the fo~ng at their add~ of. / record: 00;a~ J?Ó Ij¡J //}/ hP,Z- /(1) ú 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 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 ~) PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON sa BLDG 1050 CONNECTICUT A V NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 MURPHY E&P CO, ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 10GCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY sa, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 w NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GA THERSBURG, MD 20898 SD DEPT OF ENV & NA TRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 ENERGY GRAPHICS, MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 H J GRUY, A TTN: ROBERT RASOR 1200 SMITH STREET, STE 3040 HOUSTON, TX 77002 CHEVRON, , PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PETRINFO, DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO, LIBRARY & INFO CTR PO BOX 2100 HOUSTON, TX 77252-9987 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 ~) PURVIN & GERTZ INC, LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARATHON OIL CO, GEORGE ROTHSCHILD JR RM 2537 PO BOX 4813 HOUSTON, TX 77210 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC PO BOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 .,; RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION A TTN: CORRY WOOLlNGTON PO BOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 WATTY STRICKLAND 2803 SANCTUARY CV KA TY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY,UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE, WA 98101 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 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 ') ~ C & R INDUSTRIES, INC." KURT SAL TSGA VER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 RUBICON PETROLEUM, LLC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 TEXACO INC, Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK LOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 ) " JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE,ID 83702 MUNGER OIL INFOR SERV INC, POBOX 45738 LOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 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 PRESTON GATES ELLIS LLP, LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 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 AK JOURNAL OF COMMERCE, OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADRILL-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 ) " DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 ALASKA DEPT OF LAW, ROBERT E MINTZ ASST A TTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 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 JIM STOUFFER 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 HDR ALASKA INC, MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 US BLM AK DIST OFC, RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507-2899 ) e,' YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 GAFO,GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 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 DEPT OF NA rURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 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 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 UOA/ ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION, LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 '-' VECO ALASKA INC., CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A VRM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 w TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERA TNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 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 ASRC. CONRAD BAGNE 301 ARCTIC SLOPE A V STE 300 ANCHORAGE, AK 99518 OPSTAD & ASSOC, ERIKAOPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, SUE MILLER PO BOX196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC. MR. DAVIS. ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 PINNACLE. STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 ) .,/ GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE. AK 99518 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 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 POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC, WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE. AK 99524-3086 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 COOK INLET KEEPER, BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 .) DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV, MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 ENSTAR NATURAL GAS CO, BARRETT HATCHES POBOX 190288 ANCHORAGE, AK 99519-0288 UNOCAL, POBOX 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, INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 RON DOLCHOK PO BOX 83 KENAI, AK 99611 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 NANCY LORD PO BOX 558 HOMER, AK 99623 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 VALDEZ PIONEER, PO BOX 367 VALDEZ, AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 ') . PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS1701 VALDEZ,AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 .) BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 ::t:t: VJ .,. ': ,If". 1!" " ') BP Exploration (AlaSka). ' 900 East Benson Boulevard Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 564 5111 ') It bp June 15, 2001 Commissioners Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED .: a 0001 ¡ -I L , Alaska Oil & Gas CÜns. Commission Anchorage RE: 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, / /4~ &~ Gordon Pospisil G PB Satellites Manager Attachments Author Name Jim Young Ed Westergaard Bruce Weiler Gary Molinero Fred Bakun Position Ops. Eng. Dev. Geologist Facility Eng. Geophysicist Res. Eng Office 564-5754 564-5972 564-4350 564-5103 564-5173 CC: Randy Frazier (BP) J. P. Johnson (PAl) M. P. Evans (Exxon Mobil) P. White (Forest Oil) Aurora Pool Rules and Area 6n Order 6J " ., ... Aurora Pool Rules And Area Injection Application June 15, 2001 6/1512001 1/40 ) Aurora Pool Rules and Area 8n Order .) 6/15/2001 ¡" t I 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 Auids.............................................................................................................. 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 1 t J ,1 Aurora Pool Rules and Area In.n Order &,) 6/15/200 I I. Geology Introduction The Aurora Pool is located on Alaska's North Slope, as illustrated in Exhibit 1-1. 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-loo, 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. TheS-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 (AP A), 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-2oo 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 .) 6/15/200 I ¡, J,l 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 Band 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-l 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.n Order ~) 6/15/200 I I 1 1 .J 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 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 In. Order ~ ,) 6/15/200 I I t I 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 from oldest to youngest: C-l, C-2, C-3A, C-3B, C-4A, and C- 4B. The C-l 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 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 An Order ~ 6/15/200 I 1 J J , 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 RiverlIvishak 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 pooJ Rules and Area A ¿er &) 6/15/200 I t t I , 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. (~) 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 RiverlIvishak 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 RiverlIvishak 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. ,ionOrder .. 6/15/200 I I ~ I, 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 impenneable shales of the overlying Kalubik Formation and HRZ Shale. To the southwest and north, the pool1imit 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 P A, 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 .ion ~rder 8) 6/151200 I - Ir. 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 (kvlkh) 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-I 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 V glauconite <40%. If the volume of siderite exceeded 30%, the net pay was discounted by a factor of 0.5. Exhibit II-I 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 an Order &) 6/15/200 I . . I' 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-I. 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 psi a 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 RFf 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 .ion Order 8) 6115/200 1 viscosity was 0.722 centipoise at reservoir pressure and temperature. The bubble point for Aurora crude varied according to the sampling method. RFf 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 Perlormance 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-2OO, and S-24Ai) are unavailable for Aurora production. Six development wells have been completed and tested in the Kuparuk (S-loo, S-101, S-102, S-103, S-I04 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 owe is interpreted at 6835 feet tvdss from sidewall core data and logs. 12/40 Aurora Pool Rules and Area .00 Order .,) 6/15/2001 . . 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 owe 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 RFf 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 RFf data were collected. The entire Kuparuk interval was oil bearing and no gas or water contact was detected. The RFf pressures and oil gradient were sufficiently different (11 psi at common tvdss) from V-2OO to suggest that the S-24Ai fault block is isolated from the V-200 fault block. The API gravity of the RFf sample was 25.6 degrees. S-100 was drilled as a horizontal well in the V-2OO fault block in Phase I of Aurora development drilling. Log analysis indicates S-I00 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 API gravity was 26°. S-101 was drilled as a horizontal well in the southern portion of the V-2OO 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 .on ~'de' .) 6/15/200 1 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-10 1 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 I Under-Running Log and RFf 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 RFf 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 .n~rder .) 6/151200 I . . 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-I 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, RFf, 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 120/0 of the OOIP. Exhibit II-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 - tion Order e) 6/15/200 1 . 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 II-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-2oo Block (S-1OO, 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-1 0 1 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-10 1 will be converted to injection in the second quarter of 200 1. 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 .ion Order e) 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 ~pproximate 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 6,n lrder . 6/15/200 1 . þ , ¡ as a dynamic process. The initial strategy is derived from model studies and limited well test infonnation. 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 detennine the field off-take rate based upon sound reservoir management practices. 18/40 . J . I Aurora Pool Rules and Area_iOn Order . 6/15/200 1 III. Facilities General Overview Aurora wells will be drilled from an existing IP A drill site, S-Pad, and will utilize existing IP A pad facilities and pipelines to produce Aurora reservoir fluids to Gathering Center 2 (GC2) for processing and shipment to Pump Station No.1 (PSI). Aurora fluids will be commingled with IP A fluids on the surface at S-Pad to maximize use of existing IP A 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. IP A 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 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 IP A 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 .ion Ler . 6/15/200 I , . 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 . . Aurom Pool Rules and Area_on Order ) ~ 6/15/200 1 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 . ,J ~) Aurora Pool Rules and Area ~nOrder .) 6/15/2001 I . 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-lOO, \ S-101, S-102, S-103, S-104, and S-105are 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 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 . ' I I Aurora Pool Rules and Area _iOU Order .) 6/15/200 1 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 waterftood 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. W ell 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 .on~rder ) .' 6/15/200 1 . . , ' The following table indicates casing and tubing sizes for proposed Aurora well designs. Surface Inter / Prod Casing Production Production Casing Liner Tubing Vertical 12-114" to 7" 9-5/8" to 4-112" 5-112" to 2-7/8" 5-1/2" to 2-3/8" Horizontal 12-114" to 7" 9-5/8" to 4-1/2" 5-112" 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/lMoly, or with L-80 protected with corrosion inhibitor as necessary. Tubing jewelry will be composed of either 13-Cr or 9-Cr/lMoly, 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 SaglIvishak) utilizing a single string and multiple packers as necessary. As shown in the typical well schematics, Exhibit IV-I 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 IP A 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-loo, S-10li 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-l04i 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 6iO: Order .) 6/15/200 1 " 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-10 1i and S-102 Phase I development wells, L WD/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 6-118" horizontal section. After drilling the 6-118" horizontal hole,' a 4-112" 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 In~n Order .) 6/151200 1 I . , . 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 SSV s will be in accordance with AOGCC requirements. Drilling Fluids In order to minimize skin damage from drilling and to maintain shale stability, water- based KCl 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. 26/40 . . () Aurora Pool Rules and Area Injection Order .,) 6/15/200 1 " 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 . ' 6 ) Aurora Pool Rules and Area In~OO Order .,) 6/15/200 I I' 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-200l. The test bank meters at GC-l 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-200l. 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 .) 6/15/200 I . . VI. Area Injection Operations This application, prepared in accordance with 20 AAC 250402 (Enhanced Recovery Operations) and 20 AAC 250460 (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 250402(c). Plat of Project Area 20 AAC 250402(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, 200 1. 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 250402(c)(2) and 20 AAC 250402(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 o402( 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 250402(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 ~) 6/15/2001 I . 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 Kuparuk River Formation in S-104i; whereas further logging will be necessary to confirm cement integrity in S-10 1. 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 .) 6/15/200 I I' 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 anal ysis. lllitic 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% KCI 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 . I 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)(II) 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 " 6/15/200 1 , , 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 aud Area ion 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 ~) .) 6/15/200 I . ' Aurora Pool Rules and Area Injection Order 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 TI1N-RI2E: Sec 3: N1I2 TI2N-RI2E: Sec 17: SI/2; Sec 18: SE1I4; Sec 19: E1I2; Sec 20: All; Sec 21: All; Sec 22: W1/2NW1/4,S1I2; Sec 23: SW1I4; Sec 25: SW1I4; Sec 26 - 28: All; Sec 29: N1/2,SE1I4; Sec 32: E1/2; Sec 33 - 35: All; Sec 36: N 1/2,SW 114 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 !njl. Order .. 6/15/200 1 (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 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 6/151200 I ~ « not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 37/40 .. . ") Aurora Pool Rules and Area lulu ;rder .) 6/15/200 1 I . 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: T11N-R12E: Sec 3: N1I2 T12N-R12E: Sec 17: S1I2; Sec 18: S.E1I4; Sec 19: E1I2; Sec 20: All; Sec 21: All; Sec 22: W1I2NW1I4,S 112; Sec 23: SW1I4; Sec 25: SW1/4; Sec 26 - 28: All; Sec 29: N1I2,SEl/4; Sec 32: E1/2; Sec 33 - 35: All; Sec 36: N 1I2,SW 114 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 , . t 1 ) 1" Aurora Pool Rules and Area injectIOn Order e.) 6/15/200 I 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 Comnùssion 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 Injection Order a . ~) 6/15/200 I IX. List of Exhibits I-I 1-2 1-3 1-4 1-5 1-6 1-7 1-8 1-9 Aurora Pool Location Map Top Structure Map Aurora Participating Area (AP A) Type Log for Aurora Pool Aurora Areas Structural Cross Section Dip Seismic Cross Section Strike Seismic Cross Section Fluid Contacts 1-10 Net C4/C3B Sand Map 1-11 Net C3AJCl Sand Map 1-12 Net A Sand Map 1-13 Net Hydrocarbon Pore Foot Map II-I Model Layering and Properties II-2 Aurora Fluid Properties II - 3 PVT Properties , II-4 Production and Recovery Profiles for Primary Depletion II-5 Production and Recovery Profiles for Water Injection II-6 Porosity vs Permeability III-l Aurora Well Tie-ins - Northern S-Pad III-2 Aurora Facility Location IV -1 Typical Vertical Completion IV -2 Typical Horizontal Completion IV-3 Schrader-Kuparuk Injection Well IV -4 Aurora and GC2 Water Properties V-I Affidavit 40/40 Exhibit 1-1: Aurora Pool Location Map SANDPIPER UNIT l L ~I MILNI; POINT UNIT '-. COLVILLl~ ;~~~~:_~ë:';~:e . r\J J,,:r,~:5~:::;:' i ~~~~;R UNIT f , I :z , ' -" -.J," r'...--) ~-f ~.. \ -~'~""-" I ~"'--> , 1'-1,~\i',"'-"/ ~ F !;~> I // " (1-, /,~\ ~ '\ J -"-''''''~Ä L --- J i' -. < <;..~/ , ~ . -r :1, (,~ ;'1;;(;~\ "\ r . , DUCK ISLAND UNIT r ~ . I L.- -;r- L .-.J'tI, -, ~~'-1'~,,~ . - ~ , . . L j ,~:i',: . "1 - " . \~, I "- '" - f I ¡ ; I,Ú,í'i.' \ ..~- 1\" , \,. "I L. - --J l AURORA POOL f,~,..,---_.// 6J4!Þ~~'~ - ) - . .s r * 1'""""- 1 - "jr"'t;7-íf )¡ì - .. I - - L ., lëY /I.; \, I ~ '!II . I.!~' r' . -;-;.... . J . -' L . -. -, - . " (kLt"""<"'~f"f::'i' , r . -1 KUPARUK RIVER UNIT PRUDHOE BAy~;:t- - - . .J . .! l~_J "., ., r '-.- l..~--. ---.___._I.___-- ._..._~~- '___"--h_~~ Miles BPXA Cartooraohv/4-12-2001I1m14369.dan ~, ) \ . . t ' Exhibit 1-2: Top Structure Map ~ '" '" '" '" '" IS> .,~~ 685. e8e 615.'11118 , I 6211.111111 638,8ee _. IL-:~" L- ..... - I I .--- I I T 112it81 FEET '-- 5111 FEET STATUTE MILES' .2 .t .8 .s 1.ISTATUTEMILES Aurora Field Top C Sand Depth Map C.I. = 25 ft \ ,,) .. « , ' EXHffiIT 1-3 AURORA PARTICIPATING AREA (APA) ADl128254 I ADll28253 AD~385193 \ J \ \ I i I \ ~-t'~T-' \ --.. _.~ 1- _.. i 18 ! 17 ~ 16 1\ 15 ¡ r -\ - .... - -~ I i I I ¡ I i J ¡--: ADf=~-'----- ADY, 28256 rPBû.~~~ ~ \ I \ I?~ I ~ \ 19 I 20 I 2'1 I 22 \ 23 I . I " I Expansion I Exp i I",' \ II Area 4 Area 3 I I I to- "í ~r-----: ... ^ --"'I-"-!~- ~ -, ..-. "T I I \ I J ~ I 0 11 29 I 28 ì 27 } 26 25 i 1 ----1- I APA I --I 1 I AD~ 28259 I ~ AD~ 28258 ' ADl 28257 I ; t' \ ~ ~ 3 . ~----- ----I-------texpa~sion .-- ¡---'-' Expansion I T12Ñ~R12E , \ I A ! A ¡ J ì rea 2 I rea 1 \ \ ~ \ æ \ 34 35 ¡ 36 i j I I r I I i I I I ." ."." . ~ ,-+. .~_J .' I ~ .w .h.-. .~. ,I.. , ¡ ¡ T11 N-R12E , \ I I ! ¡ 1 \ 4 3 2 \ ¡ " i ! I I ADL\ 47450 ADL\ 28261 AD~ 28260 ---- ¡ ¡ ----- ,---- ¡ ---~--- ¡ \ \ ¡ \ \ I t ¡ - I t j 1- , f¡ 1 . ~ ;, KSDR- 1 0 0,1 MD 1000 i AH10_AIT _5_1 OT_1 0 \L. OHMM 1000 150 USIF 50 ~ CAL 1_SDN_S_1 20..sSTVD MD AH60_AIT_S_1 RHOB_1 Ib) Q. IN 0,1 OHMM 1000 1.65 G/C3 2,65 0 I- GR_AlT_S_1 AH90j.IT_S_1 NPHIS_1 GAPI 160 0.1 OI1MM 1000 60 PU 6750 ~ 6650 BASE HRZ KUPARUK C C4B C4A 6900 - 6950 '~ 7000~~':'¡~¡..:: 'u: . >~1' .', 'F" 7200 2",-,' ".',,"'..~..,.,',- ,u,;,'~,-,',~, ",."l,n .:,-; - -_oj. - ~- : - -;..--. -..1 - , ,-':',J; ,; "--¿~6 - A5 ~ ~T'~_i"- , 'C2{-:H= ~ ' - A4 7250 - - MILUVEACH 7300 --- 7150 7350 - - '\ I( I ~ ) . .) Exhibit 1-5: Aurora Areas 8811.. ., 8851"' I 81!f- \ 815.,"" " sa,- - I I R5,". I ,,8S8...8 l I: , f"'" ~" '1,- ' 1, -. : : j ¡ ,(I I i ", : , : , I... I : I - -1- -_-----L- _":'_--_I-----~-!---~, ...J-I ----- - --- --- I I. I ~ ~ ~ ~ I,"" c' 'I I I ~ =~ -- I I . .. - ~ . I ~ ¡ ,. --- I , I \ I i I ~ I I 'I \. I , -----\ - r ~ : , \ j I I i I I , , ,. - I -------,-- I CII I .j , I I . I , I ~ I~ I , ~ ~-----~t--- ~ , II I I I I I "1 I I I III J_-----_.l..--- ~ ~ I I , I , I I I I I ~ ~ I ',' ~ I I ~ {---=--==-:--+--l.L---~-----~!-:- ~ íi1 I I I I , , I , I I I I I ~~ -~rau f , III L. i . ~ I \ , ~ I \\ --¡- I , I I , ,I - l Beeche~ Block , -, , ---- -,- UI L ¡ -- \ -.. Eastern ¿' Block -I \ , I CII ~ -= i I I I - --,~ ~ ~~I,'¡ '" . I I - -- . ........ I I I - 8B.III t .S~HI 811.111 815.'" PIIT~RIT mmn .JLII~'1TR1U1! lULU Aurora FIeld 'auR Map T°l.n.~ ....... I I I I r-- I '¡~7 M'~' . ...~." ~~ . ) W'-- ..- ~...; ),' :."' :""'~"'í. .' , ......"-,,,,~.." .-'<'"~r ~~~~.;Ù-:.i~\~~?~'1 , , '~." i.~:-~ ",,' ;, .~-'~.. ,~': ~,,'.'~~j-:~ }" ~:, .Ä~--;~ ,==",,~ ~ 1 ; ~ "}/_;~}17' '-".-'- //(1( ~illIlW~l ' ~\.,.~ '\~,., ":;~,~,',,!~,','\,:~'\,.~,..,:,'" .::':;'-:'¡:;;:':':"ì"""""" ;". :-.l}~.\~ljj " ::~~~r~0~!!~...,.f~"~£.iff4~.:. l~, --,'-,?-,.,~.' :'~':,:,,'....~-,;,-,....,:":,., T,",'"',jJ'.~Î;,.~,,,:,,~t,tt,,,':;:. I' '. -' ".,.~#. ,..- .",,,_,,_,~,l U.,\@(~W' ',' ,., ,~::",",:~'::',::f~~:,~~~~ ,LJ .,...L "~~l~T~~]~ , , . ,,' '., .)~,(.. (, ~, ~" ' '~Ü''f~ " '>,' ' , ~W....~.~~:--~ """",.,..,...'ió'.: " .- ~:::~;:;;1";;;:;~:~~:-1 " ,7" , :" , " :i¡ I' i-,:.,~tÀ,',I:ri~,',,'~~~"=~"~ " t71 " ,Y" : '. ' } ¡ -""~~""~;'" " ' II~i , ::; :~,:'::::~ ",:..::L:,ro~~~ c" ,... c:.J.... ,':, ~ ~~ .. .---; i:..L.,~~~~,tJ;.~~!,..,~~~,"-, , . '. <. t!1 >< =:r ~. cr- ~. f'""'t- ~ I 0\ . . en ã (J f'""'t- ~ Þ-t f. n Þ-t 0 00 00 \J). (1) (J f'""'t- Þ-' . 0 ~ (8 J9i\!t1 5BS >lnJedn)l 3S MN ,v £ ~ -V\I v~-s 9~-S £0-8 OQ(~-^ ~# ld Áa4~aa8 v UO!~~gs ~!WS!gs d!G :L - I ~!q!rrX3 (9 (8 B .) ~ Exhibit 1-8: Strike Seismic Section 5-101 S W ',' B' N E Schrader Bluff \'~"~~,: Kuparuk , , , , ~JOO' Sag River Contact GOC WOC .) t,) Exhibit 1-9: Fluid Contacts Beechey Block V-200 Block 6678' tvdss Per (Beechey Pt St #1) Beechey Block 6835' tvdss (Beechey Pt St #2) 6824' tvdss (V-200) Crestal Block 6631' tvdss (S-16) 6812' tvdss (N Kup 26-12-12) . . .) ') &. Exhibit 1-10: Net C4/C3B Sand Map a8ll.'" '" ~llEEN- ~ Ï; . ~ I: -j- 1111.1'" 621,¡- - '" -! i "m N e."Y... _1... I' _.1 - --... P'"L- . I I I {!)- J I'IIT~I'IIT mnun! .1U8~'STII1UŒ IW.D AURORA FIELD KUPARUK C4+C38 NET SAND HAPS . . . . Exhibit 1-11: Net C3A/Cl Sand Map - --.1---------1.---- - \, ' "" ", ,.'..,.",,,',"'," r"'''' ",,' ,..,,,',"'''''' "" ',":""":' ---, - ,I ' I ,I, ",.':.,' ,I" "",,""""''':','',:'i''',,-~'''::::':, 1 ' I,' I, " , ' ,I ,'; " ,~ l I. BEECHfY¡PT_SL2!: , . ..' I .... ..'. l-i : ---~-~~:~:~~~~~~~ "~ .1~0.. . ,\ f.--f~' ;~~ ... ,. k-" III ~--- .-,-~+~~--.;...:_---4~-, ~'~--I~ " -1=øT~1" !ì~~G , ., ~l~' ----~Q) ¡-- Ø1 ¡I, ' I " , I,' :",' " 101" , Q5S-T'r I i ¡-t ,\ . ' " I' ,: , " ' ' .' - , 1 . \ I --¡ " It. .1... I. S~,,: : ; 1 ,1:.,:1,:: " "I ,,-13 \ 1 "1 ' , ,I" ' ,l. ' , ' ,', - 2 - I, .' I " " r" ", I,' IIi III J, ,,-, '-",,-,',' --"'".,._,",,1.., "-,,,-~---~'--- ,-~---- CS» -~~--+---~;-13--,,-t 7' en ~ 1 ' ",,", ", I, " , ' , ' / J 1"'- I l ~ T01 ,!......1 TE -:~~8 \.:: tf,-; ~ i-=--:_---::--+--~-;; 1-------T-~-- [-~ -----t-----/-- ¡ -j r-t ' I,', -...: 1 I , , I i .~ ~/ 1 : : : J:. _I 1 ',' UP_9_1t\_12 8Ahase One Wells v 1- ~ BIll 1.8. '88S!.. 8~~ I I 821!.. I I 82S!.: I 891.- . I _.. , --... U~ I'Kr~ra' STRTUr! "IUS~' smut! RILlS AURORA FIELD KUPARUK C3A+Cl NET SAND HAPS \ .. I I --- I .) 8) Exhibit 1-12: Net A Sand Map ~~¡~r ,,!I "¡-I' .111- ,,!'i'1- ',. V, I' I -¡ ~~_~~_~l-~-~-~~J_~"-- .'.~1LL--__~__1_-----, '1--1 ~ ':~':"-:;",:'," J:':'~'/""'.'."/: " I'" ,'\'\. --L ~ ~. .,):>' ' , I I I. I ' i " , ~ ¡.¡~ ""'" "'" ,,!I ' '! " \1 ",I :'~ I' I ' :" I " 1 ' -'"'--TT"'::------~~ I, ' " ~----" PBU Bo~ndary I ~..', ' " , "\ ' BEECHp:-PT_SL2 I :: ' ~ 5 . 1 ' , ' , I. II I ...J , ' , " " ' , ," ' I 1/ : 'I ,BEECHEY....PT;ST_1 I ',I 1 ' ',\.w . '" ' : ,.'\ """"r-~02\ "PA þound", I - ~ IL", ¡. -. . I ' " \. ' I 5-03 I ',' . ~ - I I ~': ,I, ~ , -~,.. ",' " " r"~ I:" '"I, tS) l.. , '~,__~,í' . 5-24 cl - III 1~~------I--:------~4'- ' ---I---,l=øJ, ~' , ~-!ø""" ~, ------.' -- ~ . ' ' ,\' \ ' þ-101 ",.S ' - - zOF-f'fJ I» : ~ Ell' I ' I, . "- "1.'" I -J I ' ' ' ' I ,S" 17, :,' ' I I I 1 ,:: 18 - .'5 '" ','. 5-13 I , -02 1 - I . ----~17 W-13 n I ( ~ I ::w~\-¡ ,~ , I -- t-----/-- ¡ - ~ , I ~ I I = 1 J 1 't'el~s I ~- 82S:. I 838.181 I I 821. .11 _.. - 1IIU8It.. PIEr 18~ PElT t11ITUT! RILlS ~ ITII1UÆ IJLa AURORA FIELD KUPARUK R NET SAND HAPS ...- ,L_n-- I I I I , , . > . .~ .) Exhibit 1-13: Net Hydrocarbon Pore Foot Map I , 8281'" I I 8251888 I I 831,118 I I I!." I I I ~ , , I I I I I I I I ----r-------t------ t-- , I ~ I I i "j I , I ' . , I I i I I I I I , PBU Bo~ndary I I I I I ~ , , -! I I:: I I PA :8oundary : - , -------1-- ---i- I ' I UI , I -Ì I , . 1 I I I : -t I 1 - 1 I --~-- ~ :-------t----- 1 en h , II 1 1 1 I 1 Î 1 I 1 ~J_---_--L------~ ~ ~ ): ~,:.;~:~,~,,-,~ 5-18 - : M;~ ~~~I'.L! I I I I ';. I ~ I 1 1 J 1 1 W, '::1 1 1 ,I I TE WEU- d '...-9 ì ~/ I' I, -.~ I l " I . I- 1 ..JV" ~ 1 I,' -'c I - I 1ft .1- -- -- 1 .1 _--__1-__--"':'---1- -----+------- ., -"- ColI iØ l-------T------- ,--- I, 1 I . H I I 1 , ,/Ii ., , , 1 I 1 I . 'I I I I J I _I I UP_9_~_12 8Pihase One Wells¥' ,- ~ I , I I ~V' , I I I I I ,~ I I 881.888 85.888 818.- 815.'. 821.n. 825." 8311... l~ it I DO ~ILEE~:.~11I8II i I 885,'" I J 818',888 i i. I I 1 :- I I I I I I , I 1 1 - 1 I 1 -------~-------~-------~--- I 1 1 I I , 1 , 1 I J I , 1 I 815,,'. III L .. II> 81 1ft l. iD I _. . ........ uøe. Pl!r_~Rl1 STIITUII: IIILI!S ~'1TII1'U1! IILD AURORA FIELD TOTAL KUPARUK HPF HAP ...- . -----' I I I I ) .' It Exhibit 11-1: Model Layering and Properties' A verage Properties by Simulation Layer Layer Zone Porosity Permeability 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. . 6 Exhibit 11-2: 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 psi a 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 . ) . 6 Exhibit 11-3: PVT Properties Pressure So Oil Gas Solution ~,~,ps ~~L.w~,,^~~~~~~B "^ ,_. R~~msc~, Visco.sitl,_~!~,~:;J!¥." ,^~N'WN~~~_'N cp cp scYSTB 3464 1.345 0.722 717 3100 1.316 0.843 0.744 0.022 644 """'N."."..............-.........w~","w,....,"'.",",""" "^'.w,.,..'~.'.MW""..w.'.W'"""YM"".v'NW"'W""""YH.w.W'.,..w............w.'.MW,""...""""''''^'^',' V",,,,,,^,,,,,,,,,,,".,WW.VNM'h'N,_,w""",,,,,,,,,,,,,,,w."wMYN'NN'o'NNNMWNN.WWnW,,' '-",,,,,,,,,W"''.WW.WNNo'."oYoVN.',wNW,....,,. 2750 1.289 0.945 0.789 0.020 575 2400 1.262 1.083 0.858 9 508 ww.y.WWNo.W",-".",..".w,.¡w.w",.....''''''''''''''',,, .vw...............w.,.w..........w""".."......w....",,..W'NW. ,'~'''''''''''--"N'IW.WW..,Y.''''W'''''''' Nov.....~.....""".'..w.W..NW."",^,'.""",",^'" ~",^,,^......-.oN..NM=^V'A"h"'''''''''VM'.................w.''^''''''''YoNw.y.o,v........,..........,'''''VMv. 2050 1.236 1.275 0.958 0.017 441 1700 1.210 1.554 1.100 0.016 375 '.........w.wNo'",^",N.'NN"""',''','MW,""wWN.W''....,w.v.=..w"",w,,.,.,,,...Uw..MY'o'''''Nw.',......"'W,W,""".."".',w""""",.......w.y",,YN.-NW.VN>W...,.w..w.',',''''''''''''W._"MW""'NMWh"'""""...,.._."NNN.VNo".''''WN",,,'...W''''N,W''''''''~''''''''''NNNN,,,'''WM-;WW/W."''''N.W",".',. 1350 1.185 1.987 1.280 0.015 309 1000 1.159 1.530 0.014 244 .'W""W"WNoWW-""^--"".......",^~.w,,,""'. ,,,,,www,,V',~W"~-'W"'''''''''.VWWWM -.............,NNW,,,,"""',,,,^wNVW,W..N,,,",^,,,,,.'''''. """"NN"'''''W'''''''''.''''"",,,,''''''''WNW=''''''''''''''''. "'''M~~''''~~v..o.v.''''''''''''""",,^'''''~'''''''ww. .............,..............".YW""",,"'.V',W~""''''''''''''''' 650 1.133 4.283 1.880 0.013 177 '...W.........'"",^"""W.W""""NW.VN'/W...........'^" "_''''''''''''''''NN,...,''''''WN..."""",......",......VNN ."""'.wMW""''''''''''''''''",,''''''''''''-''NNW'.''''''''''......, .......w."^"~--.,""""""".........."""""""""'" ~,,",,,,,"""-'W""""""W""'W"'N"""""""""',' .""'..,..........~ww='._....................................,,,w.... 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 B C':S ~ - Õ 30,000 25,000 - -- :E ~ 20,000 - 8 '-" B 15,000 - C':S ~ ~ 10,000 - 0 5,000 ¡ 2000 Exhibit 11-4: Production and Recovery Profiles for Primary Depletion Oil Production ...... stbd -- scf/stb 2000 2005 2010 2015 2020 2025 2030 Year Gas Production 2005 2010 2015 2020 Year 20,000 - 18,000 - 16,000 - 14,000 - 12,000 ~ - 10,000 8 - 8,000 6,000 4,000 2,000 2025 2030 ~ 10- ~ 8- 6 ~ 6- ~ Ô 4- 2 - 0 2000 900 800 - ~ 700 - ~ 600 - 'õ' 500 - êtS ~ 400 - £ 300 - C':S ~ 200 - 100 - . 2000 14 12 - Water Production 2005 2010 10,000 9,000 - A 8,000 - 7,000 - 6,000 - 5,000 - 4,000 - 3,000 - 2,000 1,000 2005 2010 2015 Year Oil Recovery 2015 Year 2020 2020 2025 2025 . 2030 ~' fit "- 2030 Exhibit II -5: Production and Recovery Profiles for Water Injection Oil Production 12,000 10,000 - 8,000 - £ ~ ~ 6,000 - - Õ 4,000 2,000 - T 2000 2005 25,000 20,000 - ~ ~ 6 15,000 - '-" M 0:: 10,000- V,) ~ 0 5,000 - ..... stbd - scflstb - 1,500 - 1,200 - 900 600 2010 2015 2020 2025 2030 Gas Production 2000 2005 2010 Year 2015 Year 2020 2025 1,800 ~ 8 300 2030 Water Production 4,000 3,500 - ~ 3,000 - 6 2,500 - ~ 2000 - 0:: ' £ 1,500- ~ ~ 1,000- 500 - . 2000 2010 2030 2015 2005 2020 2025 Year Oil Recovery 40 - 35 - ~ 30- '-" ~ 25- co ~ 20- á3 0:: 15- - Õ 10- 5 - 0 2000 . 2005 2010 2015 2020 2025 2030 Year Exhibit 111-1 Aurora Well Tie-ins - Northern S-Pad TolFrom Module 57 8-44 8-216 S-201 S-104 8-100 8-200 S-213 S-103 S-106 S-105 8 8080000s1 _s.00000008 8 808. I s.tine . WI Booster Pump (If necessary) To/From Module 93 8 Polaris Well 8 Aurora Well 8 IPA Well 0 Potential Well Productiontrest Gas Lift Piping N" . -' Production Trunk Gas Lift Trunk Test Trunk Water Injection Trunk .- Water Inj ~- . ) . ) ~ ' # " . Exhibit 111-2: Aurora Facility Location Production (#) Test (#) Gas Lift (#) Water (#) MI (#) Future Equipment (#) <I Aurora Well . Existing Polaris Well Q . IPA Well # - Surface Satellite Equipment Water Injection Booster ¡Pumps & Skids (If necessary) , .. ~ ! t r ) . 6) Exhibit IV -1: Typical Vertical Completion X-nipple @ 2000' X nipple (ID=3.813") XN nipple wlNoGo ~ ::J C _I ...L ...J If - --:~t.~u~~ -.. ::J'E: Conductor Casing 180 MD ~ 20" casing Suñace Casing 4355' MD 3285' ssTVD < 12-1/4 hole or 7-5/8 casing Tubing 4-1/2 or 3-1/2" Cr-80 Tbg 3 GLM's Production Pkr. 6600' ssTVD . . ~p~~.c ~d .p7rfs. - . . - . . - . . - . . - Kuparuk A sand perfs Production Casing 6900' sstvd < 9-7/8" hole 7 or 5-1/2 " casing "- t .. ) . 6 Exhibit IV -2: Typical Horizontal Completion j Conductor Casing I 80MD ~ 20" casing X-nipple @ 2000' :J C Surface Casing 4355' MD 3285' ssTVD 13 1/2 hole 10-3/4 or 9-5/8 casing _I Tubing 4-1/2 or 3-1/2 " Cr-80 Tbg ..l 3 GLM's 55° tangent thru HRZ Production Pkr. -1O,3OO'MD 6618'ssTVD Production Liner 11852'MD 6700-6712' sstvd 6314 hole 4-1/2 or 3-1/2" casing ~--"',:":,,,~,,,,,,,,~,,,,,,,,,,,~,:.';.,u.:.. ': -", ,!' ,--, , .,~:-"'~.':.::'-;;¡¡I"'" ....I X nipple (ID::3.813") XN nipple wlNoGo (ID::3.75") "'I"""""""""''''''''''U''''""""""""""""",,"",...... Top Kuparuk 6673' sstvd -' Intermediate Casing l04oo'MD 6678'sstvd 97/8 hole 7 or 5-1/2" casing TREE = 4-1/8" 5M WELLt-\EA 0= . FMC 11" 'ACffiJÃr<5~~NUW,_.__,w_m^"wwmw, .",.......w..','d.'.,',',',',',',"",,...,,..',',','....',',"""",,,,,,,,,-,',',',",,",',',',,,,,',',,,,,,,,,,'''''''''''''.",'''''''''''''''''''''''''''''''''' KB. ELEV = 64.5 'ï3F:"'EL§j"';;"""''''''-'''''''''N''''''''''''''à5~9' "KÕpm;~-__~-----"-"3ÕÕi" Max'Angfe';; '54"@"22ÕÖ 15átumr:;,6^^;-,,,..''''WNW,^__-w^'8798 "oaìuñï"iV6;"'''''''-''-''(370Õ'SS' ., )Exhibit IV-3: Schrader-Kupat.. )jection Well S -1 04 i SAFETY NOTES: ACTUAL DEPTHS WILL BE PROVIDED BEFORE COMPLETION 9-5/8" 40# L-80 BTC 3736' ---..JI I I 12403' I X-Nipple, 3.813" 10 1 STA MD 1VD DEV lYPEMAN LA TCH ~ GLMS 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 L SLSV 7175 5268 30 Baker CMU BK GLM1 7266 5347 30 KBG-2-T/L BK SLSV 7333 5406 30 Baker CMU BK Minimum 10 = 3.725" @ XN nipple I I I 16842' :8: ~~ 16853' 0 :8: 17061' 0 :8: :8: ----17201' L. 0 0 , 4-112" 12.6#1ft L-80 I NSCT :8: :8: ---t 8679' 1 4-1/2" X, 3.813" ID I I Baker S-3, 7" x 4.5" I I Baker SABL-3 I Baker SABL-3 1 Baker SABL-3 PERFORATION SUMMARY REF LOG: Ref Platform Express GRlRes 1/27/2001 ANGLË'ATTOPPERF:- 29 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 214/2001 f ~ [8703' 18724' l8736' 1 4-112" X, 3.813" ID I 1 4-1/2" XN, 3.725" ID I 1 4-112" WLEG I PBTD 1 1 7" 26# L-80 m-BTC 1 I 9100' I 1 9186' I ~ DATE REV BY COMMENTS 01/08/01 P. Snith Original Proposed Cofll)letion 02109/01 P. Smith As-Cofll)leted PRUDHOE BAY UNIT 1 AURORA FIELD WELL: S-104i PERMIT No: 200-196 API No: 50-029-22988-00 Sec. 35, T12N, R12E, 4494' FEL, 633' FNL BP Exploration (Alaska) OtVÆL.R:AlE 11'00 4 ;'''(1 . Exhibit IV-4: Aurora and GC2 Water Properties ;'.~lff!I~l1t:(C<~;:\: 38 . q.u: -- 247 12600 , - - 4.32 - , ' 156 ,- ,~ 6.9 1""'07 VI I ~ ~~ :~=é'=k=<,,"1 26.2 560 23,427 10754 21,932 .. (( ;tl Iþ" . Exhibit V-I AFFIDA VIT STATE OF ALASKA THIRD JUDICIAL DISTRICT I, Gordon Pospisil, declare and affirm as follows: 6) 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' /0 ( , 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: 6 ~F; /0 í /;.H~ G/~:' / Gordon Pospisil Declared and affirmed before me this lß.!!:! day of \\\\\\\\11111111/ ~, IIIr.. G I. í~ ~)... ..~..".."!.{A~ ~ ~.. r.r.~~ s . ... ... ~ ~f OT~~ \~ = :~ -. ...c.i = -. -. - .... ..-0. . - ~*\ ÜS' \CJ.L ~ ~ ...... ... ...W S ~ ..,.~ ... ..~.. ~ ~ ..",~...._........~,~ ~,(~ OF A\.ÞÌ>..~ í'111'"ln\\\\~' JUAJr¿ -'CHI I . ~ t2~ ~~, Notar#'ubli(n and for Alaska I J My commission expires: f/IÝ/ð-1 ' . - A.', ~-,J State o'f Alaska , E G AGUIRRE NOTARY PUBLIC My Commission EXpir,8S 9/141200,3 " ~~il; ::f:t:: N . 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 RE: Aurora Pool Rules And Area Injection Application Dear Com missioners: .,) ObP i?~ C~~ " 1/f4r .g ~D qqi'cf $" ~ Gq,S' °0/ ~/Jty, CQ,$ -'/O;ewe. c% . ~/$.. . "lOt¡ 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-daypublic notice period has ended. BP Exploration (Alaska) Inc., in its capacity as Aurora Operator and Unit Operator, respectfully requests that ,(;1 hearfng 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. ;;~v - Gordon Pospisil ~ GPB Satellites Manager Attachments Author Name Jim Young Ed Westergaard Bruce Weiler Gary Molinero Fred Bakun Position Ops. Eng. Dev. Geologist Facility Eng. Geophysicist Res. Eng CC: Randy Frazier (BP) J. P. Johnson (PAl) Office 564-5754 564-5972 564-4350 564-5103 564-5173 M. P. Evans (Exxon Mobil) P. White (Forest Oil) '!If' . ',j ..' .'..Ÿ , Aurora Pool Rules and Area Injection Order .) Aurora Pool Rules And Area Injection Application May 24, 2001 5/24/200 1 1/35 t Aurora Pool Rules and Aroa IDA: Order .) 5/24/2001 I. Geology.............................. .................................. ...........................................................3 In tro d u cti 0 n ..................................................................................................................... 3 Stratigraphy.............. .,."".... ...... ...................................... ........ ........ .................................3 S tm cture .......................................................................................................................... 7 F1 ui d 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.................................................................................................. 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 In~ 2der .) 5/24/2001 I. Geology Introduction The Aurora Pool is located on Alaska's North Slope, as illustrated in Exhibit 1-1. 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 WellC 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). 3/35 AJJrora Pool Rules and A>cea Inltn 2der ~) 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 Band 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-l 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 Aro> 10- Ord" .) 5/24/2001 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 Lówer 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 1n~n 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 from oldest to youngest: C-1, 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 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- 6/35 ,£. ) Aurora Pool Rules and Area I~.n Order ~ 5/24/200 1 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/lvishak 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 MO. loj,"U ~'d'" ,,) 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 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. 8/35 Aurora Pool Rules and kea In.lt .o,de, .) 5/24/2001 Fluid Contacts Exhibit 1-9 shows the interpreted OillW ater Contacts (OWCs) and Gas/Oil Contacts (GOCs) in the Aurora Pool. Based on wire line 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 (RFf) 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 RFf 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 P A, including the Expansion Areas, is within the proposed boundary of the Aurora Pool. Exhibits I-10 through 1-12 are net sandstone maps of the Aurora Pool with a contour interval of 10 feet. Exhibit I-13 is a net hydrocarbon pore foot map of the Aurora Pool with a contour interval of 10 feet. 9/35 Auro," Pool Rules and Area lnt, 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-I 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-I 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 Poot Rules and Area In- 2er .) 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-I. 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 andPt. 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 RFf downhole samples. The reservoir pressure was 3433 psia at 6700 feet tvdss (datum). The API gravity was 29.10 with a solution gas oil ratio (GOR) of 717 scf/stb. 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 nlost likely 11/35 Aur",a Pool Rules and Mea Init. O,der .) 5/2412001 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 GOe. 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 GOe pick was not clearly defined, but based on interpreted wireline log and test data the GOe 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 owe 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 owe was interpreted at 6812 feet tvdss from logs. Oil API gravity ranged 12/35 Aurora Pool Ro1es and Area lnin Order .) 5/24/2001 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 RFf 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 sef/stb. Initial API 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 sef/stb. Well logs suggest a possible GOC in the toe of the well at :=::6680 feet 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 13/35 Aurora Pool Rules and Area Inj~ 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 I 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. Be'echey 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 RFf 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. 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 Amm. Pool Rules and Aroa !nit Order .) 5/2412001 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 TI-l 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 I-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 120/0 of the OOIP. Exhibit II-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 Pool Rule, and Ar"" Ina ~der . 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 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-lOO, 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-lOl 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 kea lntt 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 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 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 In8n 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 InJ on Order . 5/24/2001 III. Facilities General Overview Aurora wells will be drilled from an existing IP A drill site, S- Pad, and will utilize existing IP A pad facilities and pipelines to produce Aurora reservoir fluids to Gathering Center 2 (GC2) for processing and shipment to Pump Station No.1 (PSI). Aurora fluids will be commingled with IP A fluids on the surface at S-Pad to maximize use of existing IP A 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. IP A 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 1II-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 IP A 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. 19/35 Aurora Pool Rules and Area I8n 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 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 bpdand 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 (SCAD A) 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 18n 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 mffiscfd) 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 I8n 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-200appraisal 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. 22/35 Aurora Pool Rules and Area In.n 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 5-112 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 I8n Order .) 5/24/2001 The following table indicates casing and tubing sizes for proposed Aurora well designs. --..------...---------------.------......-------------.._------_....------.......-----~._---------_._----_.__..-----------.----------------.-----.-.-.--------......--------.----...-.-----.-------------..-.....-.--------...---.-------'"'----.-... Surface Casing Inter / Prod Casing Production Liner Production Tubing .. .. ....---- Vertical Horizontal --- -- ---- -----.- .-------- --- -- --- ----- 12-1/4" to 7" 9- 5/8" to 4-1/2" 12-1/4" to 7" 9- 5/8" to 4-1/2" - ------- .. ------ ---------- .--- - __0. - --------- 5-1/2" to 2-7/8" 5-112" to 2-3/8" 5-1/2" to 2-7/8" 5-112" to 2-3/8" ^'VN"NYY't."""""Y~VV'Nr/'r."""'Yrh~.....V'rl'tiV'tI'INV^"'V"r/V'fI'IhY""""""""",^,""~^Y{'rl'r.Yr/Y''''''',",^Y~'''''''''''''''VJ'tN''rhYe''rl'f/'tl'NolN''^''YN^..v '^"^"''''''''''YN""^,,,^^,,,,'''''''''''''~''''''''''^''''''''''''''''''''-^'''''''''''''''YV'tI''oI'tJ'r........ Plans are to run L-80 casing in the Aurora wells. Tubing strings will be completed with either 13-Cr 9-Cr/lMoly, 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-10li 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 ) Aurora Pool Rules and Area In8n ~rder . 5/2412001 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-10li 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. L WD will include GRJResistivity 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 6-118" horizontal section. After drilling the 6-1/8" horizontal hole, a 4-112" 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 In on Order ) . 5/24/2001 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 SSV s will be in accordance with AOGCC requirements. Drilling Fluids In order to minimize skin damage from drilling and to maintain shale stability, water- based KCl mud may be used to drill through the Kuparuk Formation at Aurora. Frèshwater 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. 26/35 ., ) Aurora Pool Rules and Area lnll. 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 1._. ~der . 5/2412001 V. Production Allocation Aurora production allocation will be done according to the PBU Western Satellite Production Metering Plan. Allocation will rely on perfonnance curves todetennine 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 perfonnance curves, and to verify system perfonnance. 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-200t. 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 perfonnance 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 aud Area IU_U Order ) . 5/2412001 VI. Area Injection Operations 29/35 ) ÀUro<a Pool Rulos and Area Inj~n O,de, .) 5/24/200 1 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 T11N-R12E: Sec 3: N1I2 T12N-R12E: Sec 17: S1I2; Sec 18: SE1I4; Sec 19: E1I2; Sec 20: All; Sec 21: All; Sec 22: W1I2NW1I4,S1I2; Sec 23: SW1I4; Sec 25: SW1/4; Sec 26 - 28: All; Sec 29: N1I2,SE1I4; Sec 32: E1I2; Sec 33 - 35: All; Sec 36: N1/2,SW1I4 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. 30/35 .- ~ Aurora Pool Rules and Area In~n Order 6,) 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 1 5t each year. Rule 10: Administrative Action 31/35 t 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 a) Aurora Pool Rules and Area In-'n Order . 5/2412001 not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 32/35 ') Aurora Pool Rules and Area IDa O,der ') .' 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: T11N-R12E: Sec 3: N1/2 T12N-R12E: Sec 17: S1/2; Sec 18: SE1/4; Sec 19: E1/2; 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,SEl/4; Sec 32: El/2; Sec 33 - 35: All; Sec 36: Nl/2,SWl/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 33/35 ~ t Au""" Pool Rules aud Are. ln~n 2er .' 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 n 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). ,J 'II 34/35 ~ Aurora Pool Rules aod Area 10_0 Order ) . 5/24/2001 IX. List of Exhibits I-I Aurora Pool Location Map 1-2 Top Structure Map 1-3 Aurora Participating Area (APA) 1-4 Type Log for Aurora Pool 1-5 Aurora Areas 1-6 Structural Cross Section 1-7 Dip Seismic Cross Section 1-8 Strike Seismic Cross Section 1-9 Fluid Contacts I-IONet C4/C3B Sand Map 1-11 Net C3A1C1 Sand Map I-12Net A Sand Map 1-13 Net Hydrocarbon Pore Foot Map II-I Model Layering and Properties II-2 Aurora Fluid Properties II-3 PVT Properties II-4 Production and Recovery Profiles for Primary Depletion II-5 Production and Recovery Profiles for Water Injection III-1 Aurora Well Tie-ins - Northern S-Pad 1II-2 Aurora Facility Location IV -1 Typical Vertical Completion IV-2 Typical Horizontal Completion IV-3 Schrader-Kuparuk Injection Well 35/35 Exhibit 1-1: Aurora Pool Location Map SANDPIPER UNIT -- i.. L-ï J- _.~ ~~~~~NIT '~,-I COLVILLE RIVER UNIT ,..1- - :..-' ._~.~__~ARUNIT . r .r-=~~~7%-t~ . /\~ \.V"---....~,,--~(\ ~ I -1 1- (~yrif ---I / i!-. "0'î-^,--" ~' ~ ~ Ir""".~_/ - k e \' .. / ^-........ \ . ... ) "~, (1~'-r' ~.~. ~ ':- : ~,>~,'L I , ~¿._. I . ~_~.1, ~~~\ Ir-.., DUCK ISLAND UNIT r ~ ' J L '- ~fL...:.J~. ~ ~ .~ . ~ , . . 1.. 1 ' ;/Llf ~,-. ~. \. "'. '1 . L ' I :,. AURORA POOL 1"'-,--j~</ ~I~ L:~ . .;. '-- . J". --J r - r- .., . F. )~ ,- . ,.J .. - L, IJl .~. ;' ._;~.r-' "1.--'-'- i . I r _..J KUPARUK RIVER UNIT PRUDHOE BAy~;;:-t- - - . J . '1 I l~J ,,~~. 10 5 L- I 10 15 MIIe8 ¡ .L..---1 '! BPXA C'MtoaraDtN/4-12.2001J1m1<4369.doo . . .~ . ~) Exhibit 1-2: Top Structure Map I III. .,. 7 ,. t!l .f.5,i%~ ~ ;i.~~~~ ~,:~ð;.;fig&: f.£~ ~;:;~ ~.'~:.,;} .~:,::~.~. .," €:f;~. i~~'3 :,'~:~~ .1 , -..--'" I.~ F!ET\ . . 1 " . L:f&T mmm; MtW I .2 .1 .8 .8 .nTIrtU'Œ wun Aurora FJeld Top C Sand Depth Map CJ. = 25 ft .... "t- I - ..,..." - ._. ._---..- -,,-,,-""." ----.-." _.~...- - . . EXHmIT 1-3 AURORA PARTICIPATING AREA (APA) ADLI28254 ~- .-~,,~ -'ow r18 J - J.7 - J ! I . AD~ 28255 I :----,----_..,J--------_..t - . " I --- ¡ . I . 1 19 I 20. j I Expansion I Exp ! I Area 4 A~ea 3 ¡-.=-......, -I. -. -I . ~ I ¡ I) ! 1 10 ! 29 I i - -1- -.- I ! I ADY 28259 . ! , r . Expa~Sion I 1 Area2 I ~ I æ ¡ ¡ 1 î ~, ,._.._~~ i _J i ì ¡ \ ¡ ! AD~ 47450 ~ ! ~ J.-,-- ~ ~ ,. i J L-.. ~ ~ ~ I I ADLI28253 \ ! ¡ I ¡ I ¡ 16 ¡ ! ¡ ¡ ! AD~ 28256 I ' ----'--'----'-'- í I ¡ I ¡ ¡ ¡ . lI.u,\'r'__.~~ !"1t.. ~.t~. ~'IIÎ~UIÓ\ ¡ ¡ 27 I APA I ADL 28258 ,--+.....,--- \ i j ¡ I I I i i ¡ i ¡ 15 21 22 28 34 , 1IP""'".-:~ftCCC.P'IIJIII'" . ..II~~"-_" .~r4 4 3 ¡ ¡ ADL/28261 -- ¡ .. -------- i ! I ADLl385193 ¡ I í ! ! ¡ '-'~-ì'-""- ¡ i ¡ ! i ADU 47448 I ..~.;;~~, PBU Bo~ndary I I ì i ! ¡ ( ¡ 23 26 25 1 i - -I i ~ ~ ADl28257 1 I . --......~-~ Expansion T12N-R12E Area 1 35 36 r - L; 1 ...~ _oII'Ao.......-,~"""'...J,.\\:,- I .. ¡ T11 N..R12E ! ! 1 " , , I ! ~ ADY 28260 r' ---_._-,{-. ------~---- , -- ~ ¡ j t ¡ I ¡ f i 2 1 CAL 1_S0N_S_1 2o'~STVD MD GR_AIT_S_1 --~- ~==--' - " ~::=j - ==rS- nj~ ~" :=£' 'H"'-I'-~ - ''I ',' (--~_: ,. o~J~érC~~f I' " 1;, .L;, l' ~_:, :" :,~, -, :",. 6700 ~~!n: u,.uu..uu. I -- , -. -- ~ -I - -1- - I 'I -:- -Ij¡ ", , i . 1 ExhibitI-4: Type Log for Aurora Pool Kuparuk Section of Well V-200 API# 5002922937 Date 28 Jan 1999 Scale 1 inch = 20 feet KSDR_1 MD AH10_AIT_S,.1 ;;;, Q i :! ~ ,tl g OT_1 ¿T AH60_AIT_S_1 RHOB_1 GIC3 NPHIS_1 AH90_AIT_S_1 6750 6750 --- 6800 - 6850 6900 - 6800 t-~ - t ~.- - --- u ~-tt- ) ~ g ~ ~ ..., <> § ~ ;c i !!1 ~ 891,.11 . . ! 615111111111 I ¡$18f1'" I .~.'I'" I, 8281'" - '. ""18', I I "",'" 1(1 '{ " ~ ~' 1 '., I ~ ! -i I ¡ ~ I, ,-__I --- ----t- --------- -T----t-----~t--~t-- I .-I 1 I - ~~ , l' I I I ~ f1I1II" ,~I \ I I I : 'i \. \: : , -----\ - r ~ ~ \ \ j I I i I I , , ,. - I -------..,.-- I ØI I Ìi , -If' I ! I , I - ~) ~) Exhibit 1-5: Aurora Areas IIÞ L- ÎD I: III L i - , , 1 ~. " 1 \! --¡- I \ I I \ II - I Beeche~ Block , - I ---- -"'1- III L i .. -~ I ~ I \ ~ ~-----~t--- M \ II I I I I I 4 I I I III 1_------1.--- H ~ I I , I , I I I I I ~ ;/' ~ 1 I I ~t--~_~_~-l1___~------~\-:-~ .. I I I' I , , I , I I I I I -~ 8IiII~Øl8 f -... Eastern ¿ Block '"I \ \ I 1)1: 825.188 , 8IS~888 815.11118 818. II' -- . .....,.. S8~ FII'~P!I!' mmn .JLU~'1'nIME IISLD Aurora FIeld Fault Wap To~=k ."- ~ I I I L I CJI ø -= ! I I I - 891.11. t Exhibit 1-6: Structural Cross Section . ----; - I'" ¡ ~1 " ' ' I ~ ¡ ¡.. '~ I . f' ,"'" , ' , ,I ¡-'~I '\ ¡, ~ -' ,. " ' ,~ I t- ! I, ',:'" r ~.. ! ~~~, {" " ' ' ""I r, "'" 1 --I' ~ '¡ :H~ f-:" I i i -; , I ~~,J,',,\ " ':,,'; '" ~'5,,' ~,i'~,;,: ' ~, :,'I\CIf,",J~' é,¡;. , ' "', ,"~f,,¡ Il"',', r- .~. ç f hi, ,,: ';-,'" >1' "I ,,' .), i ",. ",~JII-,+.t ' ¡;¡ , " ' ' ' ' ;...,., F" " I " "r F'" -- <i;:J ¡L¡~-¡ ,~;¡" i'-I' ' ' , ¡,- ~~. ,,; ,~,' '~";,h,",'",.',, , 1i ~~:: """"',, ",',', ,,' " ,',=,',."," ,,' :~,~f ";1"~F,',,:~:;~j,,',,,', .,¡"'," , ~', i,'",.,', ',' , " ..,,¡. , .. ", .. ,"",",',, .. !, ""'ll .,',1 ',~': i ','" ," .- .;'\1 it'" II "'4;-;01, .. 1.< ,','" "I' i ,': 1 ' I..... .-i" 1...' ' ~ ¡ ~ /7"'~~1 ~.~~ ~"""", I .-, ~ ' 1 :\ ~~"~'ìi::-"'" ,.,,' ., 0~ ¡ :~>! ~t~'-'; '~~~ I(~./~~ ' .~U ~.','" " ,,'~~ "-::':~'~,"",'~~'~"'" A,*, , ",,' ,," ,1 !,:;~ 4,"'~, ", '~,,, "',' ,. -~~""¡1"~" ..' ,.", ,,' ~""J"'~,.' ,:I, ' ¡ ",,~'¡', :',,' J ,,'- ,'" " i'~ ,,' <I:r+:, ""I'd ,'!"i~,,' ' ,', 1.-, ,-, ~if~"""; ;, , ' ':~' ", "~' '-- ,,'; !,,' "¡J!:I"" ,-"~--'-'- 1'0' ,L", "---- '" I './'1 "" ,¡, '" 'Ì", '. ",{Ii, ,"" ¡,:~--~;~i' " '" "~ ,',,'~ t:\ i i ¡', iri,w-,~"",__ifi;,:.::-', ! "".';' ~i' .".." --..~.,,~-.~" ,j" ,;' ! " ,"" ' .,kj,', .'",' ,'I," "" .'," ",,""-:,, :t,',~" , ",',,",,~,' " ,,' " " ~"t .. ,~,,"..:'; ," 1""') .' JI .. < ,ì1,' t 'I,' .. ',-"~'., ,"""''''''''''''''''','''':'','''''','; , "",,1 ,J " '~"';¡ ,:¡---~ ~~: _I' i~.,> ,~~ pi ' it ~,,~iiF .~~'>:U ~ , ..:.. ,', " ¡,~ ~" /: "; ',', """"" ¡~ \) , J', 1";' '1 ! ,:,:o,wc;".j~" 'II: 11' , " <. ) r"'--' ' .. 1,' ,r , ¡;..! I ' !, , i ¡ ''; from '; , Ii"", ~ ,} , ¡,o" '." !.I''i'''' 'I " ; ,I, 'j" ' ',;i " VK"~'''-I'''; , , ,d" " , " n¡ ,I, I ,¡Hit '. J[¡. I ' 'J(~- t ' j , 1 ¡. . >lnJedn)l 3S MN ,HJf1!tf Bas »n18 c.t, ,v £ ~ -L^J 17 ~ -8 9~-8 £0-8 OOG- ^ ~# ld Áalpaag v UO!~~gs ~!WS!gs d!G :L -I ~!q!qx3 . 9 6 ~) Exhibit 1-8: Strike Seismic Section B '. , . ~.- I .<J~",.i'j~ s-.101 B' S w., ":~1,.oot Schrader Bluff ~:\:,.èiKt,:' Kuparuk :::. I'. '.',. Sag River Contact GOC WOC . ~ Exhibit 1-9: Fluid Contacts Beechey Block V-200 Block 6678' tvdss Per (Beechey Pt St #1) Beechey Block 6835' tvdss (Beechey Pt St #2) 6824' tvdss (V - 200) Crestal Block 6631' tvdss (S-16) 6812' tvdss (N Kup 26-12-12) .) ') ,." Exhibit 1-10: Net C4/C3B Sand Map 888.888 ... tILEEN_' L . i 685¡'" 8tl.t.. 6211mt 8251" 838. ... _. ..... .. ,.... - ...- I 1 I 1 -@- J PIIT~f'II1 mnure 'ILD~'8TITU1I ma AURORA FIELD KUPARUK C4+C38 NET SAND HAPS . ~) Exhibit 1-11: Net C3NCl Sand Map 88..e8' 8I5~.1 818.88& 815.891 t\~~.. ",t:IL£EtC' - i ~ ,I "'I \ \ I t, ;.,. 1 1 I I ~ I I I 1 ~ 1 J ~8 I \ 1 I I '\ I ,I - I I - ~--l----L- ~~------r-------î------: J/. ¡ . I " . I I I '. . - I ! / I ., P8'U: -------t------- I /1". ,----i ~ ¡ BŒCHr¡PT~'f!!' . \'< I BEECHEY_PT;'ST_t £. ,K. I . I 1)-102 I I I -~-!~~--L--- ---Î-------~-- - I ~-IU~ I ~ I ' , I . 5-1 '4 ~ ; - : V-,2oi~ tL~dft-~12-1 . I '1.0 I. . r -0 I ' I I I I' n.; -f I I .1--- ---t--~----~-- --=:[. -1=iJ~: ~ I I I 101 . N , I . ! I I I 5-1 I I I . I I I "1 J , I I J ~1 --~__~L~-_-__~ --- ~ I I I ~" ,J . I = I~ ~ r" , ,~ , I 1 I , 1 J? ' UI .J.. -- -- 1 ~ l-------T----- ~ I ,<b =~ :/ 1 I -~ 88.JIIII , us!.. !" , .. IØ '~ , ., .. .. 11!18. - -., - . --... 1'~ PD1'_~ra1 STllTUl'lIIIUS ~'1TII11J1! IUD . .... I I --< .. .1. t." 'J- AURORA FIELD KUPARUK C3A+Cl NET SAND MAPS .) .) Exhibit 1-12: Net A Sand Map III ~~ ¡ 685,.. 811111.8H ... EILEEN- ~ L . ie 181 III i IlL.- .' II , 8Is!.. CIt i1 :1 I I I - W-13-jis . w~=.1L i N-9~ I . I \- , - I +----_:......;.. '1 CII I / I ~ , I 4: , I I : ",." I J I 'ase One Wells J' I 1.1 I - ~!nl I n~- ~.n. -., . --.u... 18~ ..r~m1 ITITVI! "ILIS~'11II'IU1'! .!La AURORA FIELD KUPARUK A NET SAND MAPS ! . ..... . ,- -- I I I . ) . Exhibit 1-13: Net Hydrocarbon Pore Foot Map I, 8211818 I I 8251818 I I B!8~.1i 1 lit I I I "7"'""1~ , , I 1 I I 1 I I ~-------~------ ~-- ----I I 1 , 1 ~ 1 Ii". ~ 1 I I ~ , I I i I I I I I , PBU 8o~ndary :-"- I I UI I I i , , ;: I I:: I I PA :Soundary I , -------,-- -- T- I en I I -Ì 1 \ . , 1 I , I I -t 1 : I , --~-- ~-------+----- 1 UI ~ I 1- I -Ì ~ ¡ . . . .l¿'ø;;i~f~r~ .. ¡ i I I ~ - ~_;,2 \ " ./ 1 1 \ .,. ..',. ,-:2 - . I I i ~ i-------t-------, -- - .i . ---j¡~--t--- W-1i-Î71 ~ f-1 1 1 ' \. 5-18 , . ~1'" f I : :: .: W I I I I I 1£ ~d I 1.1-9. ~1---=-~--f ------~-------+-~,_~-Yl~~_+__---~-- ~ ç~ ~ I , JY' ill /I~ -I I ' I I I J I - _, I UP_9_((_12 8Ahase One Wells jt ,- ~ I , I I ~~ I I I I I I I I ,~ I 8aa.1II88 IllS. 188 818.888 815... 82II.UI 825.- 858.885 In L~ .. I '" EILEE~:.r i I 8851881 I' III'IRa i L. I I 1 i I I I - 1 1 , 1 I 1 1 I 1 ~------~-------4-------~--- 1 I I I I , I , I I I \ I I elS,!tM III ~ .. 81> III In L .' II U~ JlB!r_~m1 mrutI! "ILlS ~'11InU1! llLa - .. . -........ AURORA FIELD TOTAL KUPARUK HPF HRP - \ .. - , I I I I .J 6) .) Exhibit 11-1: Model Layering and Properties A verage Properties by Simulation Layer Layer Zone Porosity Permeability Gross Net Pay Initial (%) (rod) 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 Cl 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. ) .' 6) 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 (B g) 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 11-3: PVT Properties ,w~~,~~~~I!!:~". '_»'M'_'~M""'''"' ~<"""w"«,~,9,,««,«,,~,,, <"»".,»2~!,@""""",~""~,~@",,,, "",.,~~,~~!!~,,~<"" ~,",~J~,~~~~~"w,^~,v~~~,~,~~TB~^» mv~~~~~~C?!~ mvY~~.~~!!!¥w~,~~!?^~~!,!~= '~Nm'm~~'_~_~ cp cp scUSTB 3464 1.345 0.722 717 3100 1.316 0.843 0.744 0.022 644 """'......,w-.WUN"'V.'WN.W.vN'........",^......,......."'N.IW.'''''''''''''",""",,,w,,,,,.,HNWN'.'~.wu..w,,........''.....;NwM'.'WNN'ow..~,'.W""'NNw'N""'.'N'oww.v-w.w,',",I'U=''''''';'N'o''''''''',''MWMV.''''''W,W.''''''N.'W,rn..............""""",,,w,,,,,,w,,,,,,,,,,,'NW."........,,,,,...-...w......,.....,,......,,.W.hW.....""."'''V,,,;w..""""'.",,""" 2750 1.289 0.945 0.789 0.020 2400 1.262 1.083 0.858 0.019 508 ,'-""""""""'~"'NWW"^"""",""",""""""""""'''''''N.ON.~~NNW."o,^'WN^"",^,WN~''''WHMNWMY='''''''''''''''MMNWN''',^,^'''''''''_~W''''N'N ~.....................",...'""^",~""""".'""'.w-.""""""'''''N''''''''''''''''y^"""^"",,,,,,,, 2050 1.236 1.275 0.958 0.017 441 1700 1.210 1.554 1.1 0.01 375 W"""""W'N...",................w"""".................',"''''''JWN--WNW''''''''''''''''''''''''''''~w.WoI-.'.W.'.w """'^"""N."NoY."N'.'=~NNWoWOJ'- =""NWN,,,,""""M,^""V^,^,,^,,",,,,W.IW,,,~'''''W'''~N,,,,^,,'''''''''''WMI.~''.... ,"",,~""""'''''-W~'''''''''M 1350 1.185 1.987 1.280 0.015 309 1000 1.159 2.732 1.530 0.014 244 ..-.....v""","""--""""'.v.""""'^",.....WN.''''''''''''''""",,,^,^''''--^WoMWM.'N...W''''^,,^V"_N'o"N''''''''''''''''''''';.'''''MN'^~NN.'W.'''''NWNo'WoY>''''''''''''''''''~--'''''''' ~..ww.""~"""^"""'-'-"""". """""'~"""'~'"",",w=,^"",....",,,.,. 650 1.133 4.283 1.880 0.013 177 """',""",..~W"'=NN""'M............,W """"''''''~'~M''''''....,.W'''''''W;WN.......VW~~.~....".,........,.._.....~........~''''''''-'''''''w.'''''.v...',......'.....'WN''.w..MY """""""",".w..........,.....,.....-.WN.WMY.........w.w 300 1 . 1 02 9.340 2.440 0.012 105 124 1.081 21.615 2.950 0.011 61 N'MVN'''''''''''''''''''''''''",,,'''''''''''''''''''''''''N..............W. ."""",''''''NW"I'................................,.,."""....,..WWNW. .""""""'W.""'",,,,,,,,,,,,,,,,,,,""""""''''''''WHM'MY......................,..............................................,.,.............''''''''''' ....................................................vw""w",,,w..','............. """"""""w,""'''''''''W'''''''''''''''''.mww..vww.w.....,.' 0 1 .041 4.520 0 Exhibit n-4: Production and Recovery ProIDes for Primary Depletion r .2 (!:t ~ - õ 10,000 9,000 ., 8,000 - 7.000 - 6,000 - 5,000 ~ 4,000 - 3,000 2,000 1,000 Oil Production 20,000 - 18,000 - 16,000 - 14,000 - 12,000 ø:: - 10,000 8 - 8,000 6,000 -r 4,000 ~ 2,000 30,000 25,000 - s ~ 20,000 ., g ~ 15,000- ~ ð 10.000 - 5,000 ., -8-stbd -8-scflstb 2000 2005 2010 2015 2020 2025 2030 Year Gas Production 2000 2005 2010 2015 2020 Year 2025 2030 ~ 900 800 - 'Ô' 700 - :ã 600 - .0 ';;' 500 ~ Cd ~ 400 - £ 300 C'á ~ 200 - 100 - .... 2000 Water Production 2005 2010 2015 Year 2030 2020 2025 14 12 - ..-. ~ 10- ~ 8~ ~ ~ 6- ø:: ã 4- Oil Recovery 2- 0 2000 2005 2010 2015 Year 2030 2020 2025 . "-""" . Exhibit 11-5: Production and Recovery Profiles for Water Injection Oil Production 12,000 1,800 ..... stbd 10,000 - - scflstb - 1,500 8,000 - - 1,200 ~ ~ tI:S ~ 6,000 - - 900 0 ..... CJ Õ 4,000 600 2,000 300 25,000 20,000 - fS (,) Š 15,000 - '-" ~ 0:: 10,000- ~ CJ 5,000 -' 2000 2005 2010 2015 2020 2025 2030 Year Gas Production T 2000 2015 Year 2030 2020 2025 2005 2010 Water Production 4,000 3,500 - ~ 3,000 - e, 2,500 - ~ 2000 - QI:; , ~ 1,500 - tI:S ~ 1,000- 500 - . 2000 2005 2010 2015 2020 2025 2030 Year Oil Recovery 40 35 - ~ 30- '-" Q 25- 0 ð 20- ~ QI:; 15- ..... Õ 10- 5 - 0 2000 . ---/ 2005 2010 2015 2020 2025 2030 Year ToIFrom Module 57 I . ToIFrom Module 93 Exhibit 111-1 Aurora Well Tie-ins - Northern S-Pad 8-216 8-100 8-201 8-104 8-44 8-200 8-213 8-103 8-106 8-105 8 8eO 0000~8~0000000.e8088 ... 's-tUDe . WI Booster Pump (If necessary) 8 Polaris Well 8 Aurora Well 8 IPA Well 0 Potential Well ProducdonITest Gas Lift Water InJ Piping N" . ~' Production Trunk Gas lift Trunk Test Trunk Water Injection Trunk fA ~ . .) Exhibit 111-2: Aurora Facility Location Production (#) Test (#) Gas Lift (#) Water (#) MI (#) Future Equipment (#) (i Aurora Well . Existing Polaris Well fa . IPA Well # - Surface Satellite Equipment Water Injection Booster Pumps & Skids (If necessary) Injection Water Line Tie-in (IP A injection weU) ) . .) Exhibit IV -1: Typical Vertical Completion X-nipple @ 2000' X nipple (ID=3.813") XN nipple w/NoGo ..J ---!?t.~u~~_.. ::J C -' -1. ...J ~ :I' Conductor Casing I 80MD ~ 20" casing Suñace Casing 4355' MD 3285' ssTVD < 12-1/4 hole or 7-5/8 casing Tubing 4-1/2 or 3-1/2 " Cr -80 Tbg 3 GLM's Production Pkr. 6600' ssTVD .. -..-..-- --.. -. .-..- ..--.- Kuparuk C sand perfs Kuparuk A sand perfs Production Casing 6900' sstvd < 9-7/8" hole 7 or 5-1/2 " casing .) .. Exhibit IV -2: Typical Horizontal Completion j Conductor Casing I 80MD ~ 20" casing :J C X-nipple @ 2000' Suñace Casing 4355'MD 3285'ssTVD 13 1/2 hole 10-3/4 or 9-5/8 casing _I Tubing 4-112 or 3-1/2" Cr-80 Tbg ,,' fß'~1 ;~~t:~ :~~V .f:::' -1 3 GLM's ¡t~(j 55° tangent thru HRZ ¡t\~ ,::1tx :},:,~:~ :~;\ ..J j~¥f~:; ;~~~ X nipple (ID=3,813") I~ Productioo Pkr. XN nipple w/NoGo 0~\¡; l' C < -1O,3OO'MD 6618' ssTVD T~PK=~:::'1.~~,.""_",m'_,,,,,,,m=,,,,,,:"',,,,,,,,,mmmm,,,,,,mm,,,," l04oo'MD 6678'sstvd '",' , 9 7/8 hole 7 or 5-1/2" casing Production Liner 11852'MD 6700-6712's~vd 6 3/4 hole 4-112 or 3-1/2" casing , . ...........................u.... ';J;;i}';Y"¡ii3?;"¡;;l,¡!,ú~r!,:;:,w:,S."'" ~, TfiEE =¡,.. 4-1/8" 5M WELLHEAD= FMC 11" ".".'.-.".'.'.'.'.".".".".".".".'.".'.".'...-.".".".".".'.-.'-'.'-'-'.'.....-.......'~..'.'.'...'.,,'-' ACTUA TOR= ï<ä:'ËlË.\Ï ;..nu., '.. .,.."... .64:5. 'BF...ËlË\.ï .;';"."..' n..... ...,. ."35','9 ....................,............................... KOP = 300' ':~['~~~~~.:':':.:-:':':':~'~:':~~L~'~~:~' .bäiü.mïVh;;."",...,ooŠ7Ö'Ö'SŠ. . )Exhibit IV-3: SChrader-Kup,J,jection Well , S -1 04 i SAFETY NOTES: ACTUAL DEPTHS WILL BE PROVIDED BEFORE COMPLETION 9-5/8" 40# L-80 BTC 3736' --.-J I I 12403' 1 X-Nipple, 3.813" ID 1 STA MD ND DE\! TYPE MAN LATCH ~ GLMS 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 L SLSV 7175 5268 30 Baker CMU BK GLM1 7266 5347 30 KBG-2- T/L BK SLSV 7333 5406 30 Baker CMU BK Minimum ID = 3.725" @ XN nipple I I I 16842' 1 4-112" X, 3.813" ID 1 Z ~~ 16853' 1 Baker S-3, 7" x 4.5" 1 0 Z 17061' 1 Baker SABL-3 0 :8: Z --t7201' 1 Baker SABL-3 L. 0 0 I 4-1/2" 12.6#/ft L-80 I NSCT Z :8: ~8679' 1 Baker SABL-3 PERFORA TION SUMMA RY REF LOG: Ref Aatform Express GRlRes 1/27/2001 ANGLEAT"Top.ÆRF:."l 29 I Note: Refer to Production DB for historical perf data SIZE SPF INTER V AL Opn/Sqz DA TE 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 f 1. 18703' 18724' 18736' 1 4-1/2" X, 3.813" ID 1 I 4-112" XN, 3.725" ID 1 1 4-1/2" WLEG I PBTD 1 I 7" 26# L-80 m-BTC I I 9100' I I 9186' I ~ DA TE REV BY 01/08/01 p, Srrith Original Proposed Co~letion 02/09/01 p, Smith As-Co~leted COMMENTS PRUDHOE BA Y UNrr 1 AURORA FIa.D WELL: S-104i PERMrr No: 200-196 AA No: 50-029-22988-00 Sec. 35, T12N, R12E. 4494' Fa., 633' FNL BP Exploration (Alaska) atVÞSI...RAlE 11'00: ::f:f:: ~ . ~) NAME -AFFILIATION ALASKA OIL AND GAS CONSERV A TION COMMISSION Date: 5"- z. c{.0 { Time /0 .' 00 MEETING - Subiect Au r'O rtL- foe> I . fu{.e~Zi.. 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