The URL can be used to link to this page

Home My WebLink AboutAIO 020 ImagJ Project Order File Cover Þage 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 ~ direct inspection of the file. Ii Ie) 0 :J-O Order File Identifier Organizing (done) 1111111111111111111 o Rescan Needed 1111111111111111 III o Two-sided RESCAN DIGITAL DATA o Color Items: o Greyscale Items: o Diskettes, No. D Other, No/Type: OVERSIZED (Scannable) o Maps: D Other Items Scannable by a Large Scanner o Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: NOTES: D Logs of various kinds: BY: ~ I Date ,II d-¡ 0& D Other:: Project Proofing (' f " Date: I ra- êJ (P BY: {'Maria J \/\ I !J /5/ r V I' 11111111I11111111 !J /5/ m x 30 = ~ . , Date: J I~ ok, = TOTAL PAGES d q,S- (Count does not include cover sheet) J/)I1~ /5/ ( Y f Scanning Preparation BY: ~Maria'-':> + Production Scanning Stage 1 Page Count from Scanned File: rl. L¡. (p(count does include cover sheet) Page Count Matches Number in Scarming -=>reparation: V YES BY: ((Maria) Date: I'd-:". oh Stage 1 If NO in stage 1 page(s) discrepancies were found: YES BY: Maria Date: Scanning is complete at this point unless rescanning is required. ReScanned II BY: Maria Date: Comments about this file: Quality Checked I" 1111111111111111 NO vvtj /5/ NO /5/ /5/ 1111111111111111111 10/6/2005 Orders File Cover Page.doc INDEX AREA INJECTION ORDER NO. 20 Prudhoe Bay Field Midnight Sun Participating Area Midnight Sun Oil Pool 1. February 17, 2000 Pool Rule request for Midnight Sun 2. February 25, 2000 Notice of Public Hearing and Affidavit of Publication 3. March 27, 2000 ARCO's request to reschedule hearing 4. April 1, 2000 Notice of Hearing Cancellation 5. May 3, 2000 Phillips' request for Hearing, Midnight Sun Oil Pool Rules, and AIO 6. May 10, 2000 Notice of Public Hearing 7. May 25, 2000 Email 8. June 19, 2000 Email 9. June 13, 2000 Sign -in sheet 10. June 21, 2000 Midnight Sun Oil Pool Rules and AIO, revised 11. June 21, 2000 Sign -in sheet 12. June 21, 2000 Transcript 13. September 27, 2004 AOGCC Proposal to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells 14. June 20, 2007 BPXA's request for hydro testing for the PBU 207 Pipeline Replacement Project (AIO 20.001) 15. April 30, 2012 BPXA's request for standardization of authorized fluids for FOR and pressure maintenance (AIO 20.002 and AIO 20.002 Amended) 16. August 27, 2014 BPXA's request to authorize the use of miscible injectant and other hydrocarbon gases to enhance recovery from the Midnight Sun Oil Pool (AIO 20.003) INDEX AREA INJECTION ORDER NO. 20 a . . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The APPLICATION OF PHILLIPS ALASKA, Inc. ("PHILLIPS") for an order allowing injection of fluids for enhanced oil recovery in the Midnight Sun Oil Pool, Midnight Sun Participating Area, Prudhoe BayField. ) Area Injection Order No. 20 ) Prudhoe Bay Field ) Midnight Sun Participating Area ) Midnight Sun Oil Pool ) ) September 28, 2000 IT APPEARING THAT: 1. By letter dated February 17, 2000, and application dated May 3, 2000, Phillips Alaska, Inc. ("PHILLIPS") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to allow injection of fluids for enhanced oil recovery into the Midnight Sun Oil Pool. PHILLIPS provided supplemental information on June 12, 2000. 2. Notice of Public Hearing was published in the Anchorage Daily News on February 25, 2000, and a hearing was scheduled for April 4, 2000. On March 27, 2000, PHILLIPS requested the hearing be rescheduled. On April 1, 2000, a Notice of Cancellation of Public Hearing was published in the Anchorage Daily News. A second Notice of Public Hearing was published in the Anchorage Daily News on May 10,2000, and the hearing was rescheduled to June 13,2000. 3. A hearing concerning the applicant's request \-vas convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 on June 13,2000. Concurrently, the Commission heard testimony to establish pool rules for the Midnight Sun Oil Pool. FINDINGS: 1. Commission regulation 20 AAC 25.460 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. 2. PHILLIPS presented testimony in support of an application for pool rules and area injection order for the proposed Midnight Sun Oil Pool ("MSOP") on June 13,2000. 3. The Midnight Sun Participating Area is located within the Prudhoe Bay Unit (PBU) on Alaska's North Slope. 4. The Commission approved the designation of BP Exploration (Alaska) Inc. ("BPXA") as sole operator of the PBU effective July 1,2000. 5. BPXA is the designated operator of all wells within one-quarter mile of the area proposed for enhanced oil recovery. The State of Alaska is the surface owner. 6. The U.S. Environmental Protection Agency has exempted all aquifers in the Western Operating Area of the Prudhoe Bay Field, including the area containing the MSOP by letter dated July 1, 1986. The EP A action was considered a minor exemption and a non-substantial program revision and did not require notice in the Federal Register (Aquifer Exemption Order No. 1, July 11, 1986. Area Injection Order No. 20 September 28, 2000 Page 2 - e 7. The MSOP is contained within the Lower Cretaceous-aged Kuparuk Formation and correlates with the interval between the measured depths of 11,662 and 11,805 feet in the PBU E-100 well. The interval lies approximately 8,000 feet below sea level with a typical gross sand thickness of about 110 feet. 8. Within the MSOP, the Kuparuk Formation can be informally divided into upper and lower lithologic units. The upper unit ranges from 0 to 70 feet in thickness, and consists of interbedded sandstone that contains varying amounts of glauconite, siderite and minor amounts of muddy siltstone. The lower unit is about 40 feet thick. The lower unit is generally composed of very fine to fine grained, quartz- rich, porous sandstone. 9. Mean porosity in the upper Kuparuk unit is 20.7% and mean permeability is 200 millidarcies. Mean porosity and penncability in the reservoir interval of the lower Kuparuk unit are 27.3% and 760 millidarcies, respectively. Mean water saturation is 26.4% for the upper Kuparuk Formation and 12.6% for the reservoir interval of the lower Kuparuk unit. 10. The Kuparuk Formation is confined above by approximately 110 feet of shale assigned to the Kalubik and High Radioactive (HRZ) Zones. Log derived mechanical properties for the Kalubik / HRZ indicate a fracture gradient of 0.8 to 0.9 psi/ft. 11. Approximately 950 feet of shale in the Miluveach and Kingak Formations confines the Kuparuk Formation below. A single leakofftest in the Kingak shale yielded a leakoff gradient of approximately 0.85 psi/ft. 12. No tests have been conducted at MSOP to determine breakdown pressure for the Kuparuk Formation. Fracture gradient data from offset fields ranges between 0.6 and 0.7 psi/ft at initial reservoir conditions. 13. MSOP crude oil gravity is approximately 25.5 degrees API, solution gas-oil-ratio is 717 scf/stb, formation volume factor is 1.33 reservoir barrels per stock tank barrel, and oil viscosity is 1.68 centipoise at the bubble point pressure, 4045 psia. Initial reservoir pressure is 4058 psia and temperature is 160 degrees Fahrenheit at the reservoir datum of 8050 true vertical depth sub sea. 14. Steady state water-oil relative permeability data indicate 23% residual oil saturation on a core flood test. Limited results from centrifuge water-oil and gas-oil experiments indicate water-oil relative permeability for MSOP should be similar to that measured for other North Slope fields. Analog data were used in predictive model reservoir performance studies. 15. Gas coning and gas under-running may impact reservoir performance as the gas cap overlies slightly more than 50% of the oil column. 16. Simulation results indicate recovery will be maximized ifvoidage is balanced by injecting water into the PBU E-IOO well in the mid-field area of the MSOP once reservoir pressure has been restored to the 3800 to 4000 psi range. 17. Well PBU E-100 will be converted to injection service at a rate of 20,000-25,000 barrels of water per day. 18. MSOP oil production is expected to peak at a rate of 8,000 to 10,000 barrels per day prior to waterflood breakthrough. 19. Injection water will come from two source water wells drilled at PBU E-Pad and completed in the Tertiary-age, Sagavanirktok Formation. Produced water from Gathering Center #1 (GC-l) or produced water separated directly from Midnight Sun production at E-Pad will be considered as potential alternative sources of injection water. 20. Produced water samples analyzed from nearby well DS #15-06 and GC-l provided 47,005 mg/l and 19,985 mg/l total dissolved solids, respectively. Area Injection Order No. 20 September 28, 2000 Page 3 e e 21. Geochemical model results indicate that a combined Tertiary water and connate water is likely to form calcium carbonate and barium sulfate scale. Similar scale precipitation is anticipated for produced water. Scale will be controllcd with commonly available inhibitors. 22. Expected average wellhead injection pressure is 2250 psig, maximum wellhead injection pressure is 2750 psig, and maximum bottom hole pressure is 6000 psig. 23. PHILLIPS stated maximum injection pressurc is not likely to initiatc or propagate fractures through confining strata based on fracture propagation models, mechanical property logs and analog information from other Kupamk formation developments. 24. Well PBU E-100 is completed with 9 5/8" 47 #/ft casing to 4,441' measured depth (MD), 7" 29 #/ft casing set at 12,906'MD, and 4 Yz" 12.6 #/ft tubing set to 11,646' MD, with a 7" packer at 11,620' MD. Open perforations are from 11,775' to 11,790' MD. 25. A cement bond log mn on well PBU E-100 indicates top of cement lies at 10,650' MD, with adequate cementation above the perforations. A copy of the log is on file with the Commission. 26. BPXA will demonstrate the mechanical integrity of well PBU E-100 as specified in 20 AAC 25.412 prior to initiating injection operations. 27. The operator will comply with the requirements of20 AAC 25.402 (d) and (e) to monitor tubing- casing annulus pressures of injection wells periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength of the casing. 28. All existing wells drilled within the proposed project area have been constmcted in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105 and 20 AAC 25.112, or an equivalent precursor regulation. 29. PHILLIPS envisions a three-well field, including the drilling of one additional upstmcture producing well. Additional injection and production wells may be considered depending on reservoir performance and ongoing technical evaluation. 30. The estimated original oil in place ("OOlP") in the MSOP ranges from 40 to 60 MMBO. Total gas in place is estimated between 100 to 130 bscf. Free gas volume associated with the gas cap is estimated between 60 and 80 bscf. 31. Recovery estimated from reservoir simulation of primary depletion is approximately 14% of the OOlP, about 6 to 8 MMBO. Estimates of incremental waterflood recovery ranges from 15 to 25% of the OOIP, or 10 to 15 MMBO, with 0.7 pore volumes of water injected. CONCLUSIONS: 1. The application requirements of 20 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. The U.S. Environmental Protection Agency has exempted all aquifers in the Westem Operating and K-Pad Areas ofthe Pmdhoe Bay Field, including the proposed MSOP by letter dated July 1, 1986 (Aquifer Exemption Order No.1, July 11, 1986). 4. The proposed injection operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 6. Injection water limited to that produced is the most beneficial and efficient approach to enhanced recovery at this time. Area Il\iection Order No. 20 September 28, 2000 Page 4 e - 7. The proposed MSOP water injection project will result in 15 to 25 percent (about 10 to 15 million barrels) increased recovery over primary production alone. 8. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or diselose 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 following rules, in addition to statewide requirements under 20 AAC 25, govem Class II enhanced oil recovery injection operations in the affected area described below: UMIAT MERIDIAN Tl2N Tl2N Rl3E Section 25, S Yz; Section 36, N Yz, SE Y4, E Yz of SW 1/4 R14E Section 29, all; Section 30, S Yz, S Yz ofNE Y4, S Yz ofNW Y4; Section 31, N Yz, SW Y4, N Yz of SE Y4; Section 32, NW Y4; Section 28, W Yz, W Yz ofNE Y4, W Yz of SE Y4 Rule 1 Authorized Iniection Strata for Enhanced Recoverv Within the affected area, fluids appropriate for enhanced 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 11,662 and 11,805 feet in the PB U E-l 00 well. Rule 2 Fluid Iniection 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 3 Monitorin2 the Tubin~-Casin2 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 Reportin2 the Tubin2-Casin2 Annulus Pressure Variations Tubing-casing annulus pressure variations between consecutive observations need not be reported to the Commission unless \vcll integrity failure is indicated as in Rule 6 below. Rule 5 Demonstration of Tubin2-Casin2 Annulus Mechanical Inte2ritv A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing ammlus 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 by the vertical depth of the packer, whichever is greater, will be used. The test pressure must show a stabilizing trend and must not decline more than 10% in a thirty-minute Area Injection Order No. 20 September 28, 2000 Page 5 e e 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 Inte2.ritv 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 7Plu~2.in2. and Abandonment ofIniection 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 or Federal agency remain the operators' responsibility. Rule 9 Administrative Action Upon proper application, the Commission may administratively waive the requirements of any mle stated above or administratively amend any mle 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, Alas~~~~d dated September 28, 2000 ~~ Camillé Oechsli Taylor, Commis oner Alaska Oil and Gas Conservation Commission Dani . Seamount Jr., ommlSSlOner Alaska Oil and Gas nservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order. a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order. or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commls<ion can refuse an application by not acting on it within the lO-day period. An affeeted 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., 10th day after the application for rehearing was filed) Unl I 1VI1,......1 .. , ,III Randall Nottingham 24 Hartwell Lexington, MA 02173 PIRA ENERGY GROUP LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 OVERSEAS SHIPHOLDING GRP ECON DEPT 1114 AV OF THE AMERICAS NEW YORK, NY 10036 NY PUBLIC LIBRARY DIV E GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 ALASKA OFC OF THE GOVERNOR JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 ARENT FOX KINTNER PLOTKIN KAHN LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 LIBRARY OF CONGRESS STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 TECHSYS CORP BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 e e US GEOLOGICAL SURVEY LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 DPC DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 SD DEPT OF ENV & NATRL RESOURCES OIL & GAS PROGRAM 2050 W MAl N STE #1 RAPID CITY, SD 57702 AMOCO CORP 2002A LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ILLINOIS STATE GEOL SURV LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 LINDA HALL LIBRARY SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 MURPHY E&P CO ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 UNIV OF ARKANSAS SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 CROSS TIMBERS OPERATIONS SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 e e DWIGHTS ENERGYDATA INC JERLENE A BRIGHT DIRECTOR PO BOX 26304 OKLAHOMA CITY, OK 73126 e e IOGCC POBOX 53127 OKLAHOMA CITY, OK 73152-3127 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 OIL & GAS JOURNAL LAURA BELL POBOX 1260 TULSA, OK 74101 GAFFNEY, CLINE & ASSOC., INC. LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 MARK S MALlNOWSKY 15973 VALLEY VW FORNEY, TX 75126-5852 US DEPT OF ENERGY ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 DEGOL YER & MACNAUGHTON MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 JERRY SCHMIDT 4010 SILVERWOOD DR TYLER, TX 75701-9339 STANDARD AMERICAN OIL CO AL GRIFFITH POBOX 370 GRANBURY, TX 76048 CROSS TIMBERS OIL COMPANY MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 PRITCHARD & ABBOTT BOYCE B BOLTON PE RPA 4521 S. HULEN STE 100 FT WORTH, TX 76109-4948 SHELL WESTERN E&P INC G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 ENERGY GRAPHICS MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 H J GRUY ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 PURVIN & GERTZ INC LIBRARY 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 RAY TYSON 1617 FANNIN ST APT 2015 HOUSTON, TX 77002-7639 CHEVRON PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 BONNER & MOORE LIBRARY H20 2727 ALLEN PKWY STE 1200 HOUSTON, TX 77019 e e OIL & GAS JOURNAL BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 PETRAL CONSULTING CO DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 MARK ALEXANDER 7502 ALCOMITA HOUSTON, TX 77083 MARATHON OIL CO GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 UNOCAL REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 EXXON EXPLOR CO LAND/REGULATORYAFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 EXXON EXPLORATION CO. T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 CHEVRON USA INC. ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 PETRINFO DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 PHILLIPS PETROLEUM COMPANY W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 e e PHilLIPS PETR CO ALASKA LAND MGR POBOX 1967 HOUSTON, TX 77251-1967 WORLD Oil DONNA WilLIAMS POBOX 2608 HOUSTON, TX 77252 EXXONMOBll PRODUCTION COMPANY J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 EXXONMOBll PRODUCTION COMPANY GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 PENNZOll E&P Will D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 CHEVRON CHEM CO LIBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 MARATHON Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 ACE PETROLEUM COMPANY ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 PHilLIPS PETR CO JOE VOELKER 6330 W lP S RM 492 BElLAIRE, TX 77401 PHilLIPS PETR CO ERICH R. RAMP 6330 W lOOP SOUTH BElLAIRE, TX 77401 e e PHILLIPS PETR CO PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TEXACOINC R Ewing Clemons POBOX 430 BELLAIRE, TX 77402-0430 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 TESORO PETR CORP LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 INTL OIL SCOUTS MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 AMOCO PROD CO LIBRARY RM 1770 JILL MALLY 1670 BROADWAY DENVER, CO 80202 C & R INDUSTRIES, INC. KURT SALTSGAVER 1801 BROADWAY STE 1205 DENVER, CO 80202 e e US GEOLOGICAL SURVEY LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901-1655 RUBICON PETROLEUM, LLC BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, 10 83702 RUI ANALYTICAL JERRY BERGOSH POBOX 58861 SALT LAKE CITY, UT 84158-0861 TAHOMA RESOURCES GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 US GEOLOGICAL SURVEY LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 MUNGER OIL INFOR SERV INC POBOX 45738 LOS ANGELES, CA 90045-0738 LA PUBLIC LIBRARY SERIALS DIV 630 W 5TH ST LOS ANGELES, CA 90071 e e BABSON & SHEPPARD JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH, CA 90808-0279 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 ORO NEGRO, INC. 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 76 PRODUCTS COMPANY CHARLES BURRUSS RM 11-767 555 ANTON COSTA MESA, CA 92626 TEXACO INC Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 US GEOLOGICAL SURVEY KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 SHIELDS LIBRARY GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 ECONOMIC INSIGHT INC SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 US EPA REGION 10 LAURIE MANN OW-130 1200 SIXTH AVE SEATTLE, WA 98101 e e MARPLES BUSINESS NEWSLETTER MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 DEPT OF REVENUE OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 GUESS & RUDD GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA 725 CHRISTENSEN DR STE 4 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 FORCENERGY INC. JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 YUKON PACIFIC CORP JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 e e PRESTON GATES ELLIS LLP LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 ALASKA DEPT OF LAW ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 GAFO GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF REVENUE OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 BRISTOL ENVIR SERVICES JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 HDR ALASKA INC MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 BAKER OIL TOOLS ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 N-I TUBULARS INC 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADARKO MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 e e ALASKA OIL & GAS ASSOC JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 e e ANADRI LL-SCH LUMBERGER 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 AKJOURNALOFCOMMERCE OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99503-5911 DEPT OF NATURAL RESOURCES PUBLIC INFORMATION CTR 3601 C STREET STE 200 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JIM STOUFFER 3601 C STREET STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 3601 C ST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JULIE HOULE 3601 C ST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OIL & GAS WILLIAM VAN DYKE 3601 C ST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS BRUCE WEBB 3601 CST STE 1380 ANCHORAGE, AK 99503-5948 FINK ENVIRONMENTAL CONSULTING, INC. THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 RUSSELL DOUGLASS 6750 TESHLAR DR ANCHORAGE, AK 99507 STU HIRSH 9630 BASHER DR. ANCHORAGE, AK 99507 AMERICA/CANADIAN STRATIGRPH CO RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 US BLM AK DIST OFC RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507-2899 TRADING BAY ENERGY CORP PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 e e UNIVERSITY OF ALASKA ANCHORAGE INST OF SOCIAL & ECON RESEARCH A TERESA HULL ., 3211 PROVIDENCE DR ANCHORAGE, AK 99508 e US MIN MGMT SERV AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV RICHARD PRENTKI 949 E 36TH AV 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 US MIN MGMT SERV RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 REGIONAL SUPRVISOR, FIELD OPERATNS MINERALS MANAGEMENT SERVICE ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 USGS - ALASKA SECTION LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 CIRI LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 ANCHORAGE TIMES BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 ARCO ALASKA INC JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC STEVE BENZLER A TO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC LIBRARY POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC MARK MAJOR ATO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC SAM DENNIS ATO 1388 POBOX 100360 ANCHORAGE, AK 99510-0360 e e ARCO ALASKA INC SHELlAANDREWS ATO 1130 PO BOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 ARCO ALASKA INC KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 AL YESKA PIPELINE SERV CO CHUCK O'DONNELL 1835 S BRAGAW - MS 530B ANCHORAGE, AK 99512 AL YESKA PIPELINE SERV CO PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 AL YESKA PIPELINE SERV CO LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 US BUREAU OF LAND MGMT OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV#13 ANCHORAGE, AK 99513-7599 ANCHORAGE DAILY NEWS EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 JWL ENGINEERING JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 e e NORTHERN CONSULTING GROUP ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE, AK 99517 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 ASRC CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 DAVID CUSATO 600 W 76TH A V #508 ANCHORAGE, AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 OPST AD & ASSOC ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 ENSTAR NATURAL GAS CO BARRETT HATCHES POBOX 190288 ANCHORAGE, AK 99519-0288 MARATHON OIL CO BRAD PENN POBOX 196168 ANCHORAGE, AK 99519-6168 e e MARATHON OIL CO OPERATIONS SUPT POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL POBOX 196247 ANCHORAGE, AK 99519-6247 UNOCAL KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 EXXONMOBIL PRODUCTION COMPANY MARK P EVANS PO BOX 196601 ANCHORAGE, AK 99519-6601 BP EXPLORATION (ALASKA), INC. MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 AMSINALLEE CO INC WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 e e PINNACLE STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 D A PLATT & ASSOC 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 DIANA FLECK 18112 MEADOW CRK DR EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 COOK INLET VIGIL JAMES RODERICK POBOX 916 HOMER, AK 99603 COOK INLET KEEPER BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 PHILLIPS PETR ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 RON DOLCHOK POBOX 83 KENAI, AK 99611 DOCUMENT SERVICE CO JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 e e KENAI PENINSULA BOROUGH ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 NANCY LORD PO BOX 558 HOMER, AK 99623 PENNY VADLA POBOX 467 NINILCHIK, AK 99639 BELOWICH COAL CONSULTING MICHAEL A BELOWICH HC31 BOX 5157 WASILLA, AK 99654 PACE SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 KENAI NATL WILDLIFE REFUGE REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ PIONEER POBOX 367 VALDEZ, AK 99686 AL YESKA PIPELINE SERVICE CO VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 VALDEZ VANGUARD EDITOR POBOX 98 VALDEZ, AK 99686-0098 e e NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 UNIV OF ALASKA FAIRBANKS PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 JACK HAKKILA POBOX 61604 FAIRBANKS, AK 99706-1604 FAIRBANKS DAILY NEWS-MINER KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 C BURGLlN POBOX131 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 K&K RECYCL INC POBOX 58055 FAIRBANKS, AK 99711 ASRC BILL THOMAS POBOX 129 BARROW, AK 99723 e e RICHARD FINEBERG PO BOX416 ESTER, AK 99725 UNIV OF ALASKA FBX PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 UNIVERSITY OF ALASKA FBKS PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 DEPT OF ENVIRON CONSERV SPAR CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 e e . . SARAH PALIN, GOVERNOR AI,ASIiA OIL AND GAS CONSERVATION COMMISSION 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. AIO 3.018 ADMINISTRA TIVE APPROVAL NO. AIO 4E.023 ADMINISTRATIVE APPROVAL NO. AIO 20.001 ADMINISTRA TIVE APPROVAL NO. AIO 24A.OOl ADMINISTRATIVE APPROVAL NO. AIO 25A.OOl ADMINISTRA TIVE APPROVAL NO. AIO 26A.00l Ms. Colleen Burgh Waste Technical Authority BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 RE: Request for Administrative Approval to Inject Hydrotest Water Prudhoe Bay Unit Oil Pools Dear Ms. Burgh: BP Exploration (Alaska), Inc. ("BPXA") has notified the Commission of ongoing and planned construction of replacement oil transit pipeline segments throughout the Prudhoe Bay Unit fields. The pipeline segments must undergo pressure testing (referred to as "hydrotesting") to verify integrity. Filtered lake water that is chemically treated with a corrosion inhibitor and an oxygen scavenger will be used for hydrotesting the pipeline segments. The Commission has previously approved the injection of filtered and treated lake water used to hydro test a pipeline segment between Lisburne Ll production pad and the Lisburne Production Center ("LPC"), part of the Greater Point McIntyre development area. Administrative approval under Area Injection Order ("Ala") 4E authorized, as an enhanced recovery injection fluid, hydrotest water consisting of treated and filtered lake water stored for fire fighting purposes (refer to Ala 4E.22). The Commission approves BPXA's June 20, 2007 written request for authorization to inject hydrotest water as an enhanced recovery fluid. The composition of hydrotest water referred to in BPXA's current request appears to be no different than that used to test the Lisburne replacement pipeline segment. BPXA has demonstrated to the satisfaction of the Commission that the hydrotest water, as described in the June 20, 2007 ïequest, is consistent and compatible with fluids used in routine enhanced recovery operations in the Prudhoe Bay Unit oil pools and will not adversely impact the reservoir or production equipment. EOR Injection of HYdrot~ater June 21, 2007 Page 2 of2 . The following Ala rules governing lllJection operations in Prudhoe Bay Unit oil pools are amended to include filtered and chemically treated lake water used for hydro testing replacement pipeline segments to the list of fluids authorized for enhanced oil recovery injection: Ala 3 (Prudhoe Oil Pool), Rule 1 Ala 4E (Prudhoe Oil Pool), Rule 1 Ala 20 (Midnight Sun Oil Pool), Rule 1 Ala 24A (Borealis Oil Pool), Rule 2 Ala 25A (Polaris Oil Pool), Rule 3 Ala 26A (Orion Oil Pool), Rule 3 Any change in the composition of the hydro test water that has the potential to affect its compatibility with formation fluid or the normal enhanced recovery injection fluid will require additional review by the Commission before injection occurs. Similarly, any change in treating chemical use that results in the hydrotest fluid exhibiting hazardous characteristics will require additional review. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. DONE at Anchorage, Alaska and dated June 21, 2007. ¿ 2 Mary Jones XTO Energy Inc Cartography 810 Houston Street. Ste 2000 Ft Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 BOise, 10 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . David McCaleb IHS Energy Group GEPS 5333 Westhelmer. Ste 100 Houston. TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 . Mona Dickens Tesoro Refining and Marketing Co Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 - ¡ IJubllc \JOliet Lone Creek ':4 and \dmm i\PPi'S PBL . Subject: Public Notice Lone Creek #4 and Admin Approval's PBL~ From: Jody Colombie <jody_colombie"ª",admin.state.ak.us> Date: Thu. 21 Jun 2007 14:55:49 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, trmjr 1 <trmjr 1 @aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly <shannon.donnelly@conocophillips.com>, "Mark P. Worcester" <mark.p.worcester@conocophilIips.com>, Bob <bob@inletkeeper.org>, Dave Roby <dave JO by@admin.state.ak. us>, b britch <b britch@alaska.net>, m j nelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. Sommer" <SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, doug_schultze <doug_ schultze@xtoenergy.com>, Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesnol@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>,jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net>, eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <bl@mapalaska.com>,jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, Julie Houle <julie_houle@dnr.state.ak.us>, John W Katz <jwkatz@alaskadc.org>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmc1ean<rmclean@pobox.alaska.net>, mkm 7200 <mkm nOO@aol.com>, Brian Gillespie <itbmg@uaa.alaska.edu>, David L Boelens <dboelens@aurorapower.com>, Todd Durkee <todd.durkee@anadarko.com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, James Scherr <james.scherr@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda _ Kahn@fws.gov>, Jerry Dethlefs <Jerry. C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.belman@conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>, Gary Rogers <gary _rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Biil Walker <biii-wwa@ak.net>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <cammy_taylor@dnr.state.ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, Stephen F Davies <steve_davies@admin.state.ak.us>, of2 6/21/20072:56 PM Public NOlice Lone Creek ;:,4 and Admin APPIIS PBC . Keith Wiles <kwiles@marathonoil.com>. Deanna Gamble <dgamble@kakivik.com>, James B Regg <jim _regg@admin.state.ak.us>, Catherine P Foerster <cathy_ foerster@admin.state.ak.us>, gregory micallef <micallef@clearwire.net>, Laura SiUiphant <laura _ siUiphant@dnr.state.ak.us>, David Steingreaber <david.e.steingreaber@exxonmobil.com>, akpratts@acsalaska.net, Robert CampbeI1 <Robert.Campbell@reuters.com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>, Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner <jimwinegamer@brooksrangepetro.com>, Matt Rader <matt_rader@dnr.state.ak.us>, carol smyth <caroI.smyth@shelI.com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@marathonoi1.com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@internationa1.gc.ca>, Cary Carrigan <cary@kfqd.com>, Sonja Prankllin <sfranklin6@bloomberg.net>, Mike Bill <Michae1.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan_birnbaum\"@law.state.ak.us>, Randall Kanady <Randal1.B.Kanady@conocophillips.com>, MJ Loveland <N1878@conocophillips.com>, Christian Gou-Leonhardt <Christian_ Gou- Leonhardt@legis.state.ak. us> Jody Colombie <jody colombie(~admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content- Type: application/pdf various admin approvals AIO.pdf Content-Encoding: base64 Content- Type: application/pdf Lone Creek Content-Encoding: base64 201'2 6/21/20072:56 PM • • � �� Th A__.ASEI(KL--;\ / SEAN PARNELL, GOVERNOR O ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMDIISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 ADMINISTRATIVE APPRO AL FAx (907) 276 -7542 AREA INJECTION ORDER NO. 20.002 Ms. Allison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: Authorized Fluids for EOR and Pressure Maintenance of the Midnight Sun Oil Pool Dear Ms. Cooke: By letter dated April 30, 2012, BP Exploration (Alaska) Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the following Area Injection Orders (AIO): 3A, 4E, 14A, 20, 22E, 24B, 25A, 26B and 31. BPXA requested the amendments in an effort to standardize the fluids authorized for injection for enhanced recovery and pressure maintenance for the oil pools in the Prudhoe Bay Field. BPXA requested the standardization due to the complexity of managing injection operations for multiple pools, with different lists of authorized fluids, which are served by common production facilities. In accordance with terms set forth below, BPXA's request is partially APPROVED, with a minor change to the wording proposed by BPXA. BPXA's request to inject produced gas and enriched hydrocarbon gas is hereby DENIED. BPXA proposes that AIO No. 14A be modified to approve the following for EOR and pressure maintenance injection. - Produced water and gas; - Enriched hydrocarbon gas; - Non - hazardous water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 10 degrees F); - Fluids introduced to production facilities for the purpose of oil production, plant operations, plant /piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Includes but not limited to: o Freeze protection fluids; o Fluids in mixtures of oil sent for hydrocarbon recycle; o Corrosion/scale inhibitor fluids; AIO 20.002 • • September 4, 2012 Page 2 of 4 o Anti -foams /emulsion breakers; o Glycols - Non - hazardous glycols and glycol mixtures; - Fluids that are used for their intended purpose within the oil production process. Includes: o Scavengers; o Biocides - Fluids to monitor or enhance reservoir performance. Includes: o Tracer survey fluids; o Well stimulation fluids; o Reservoir profile modification fluids. As shown above, the list of fluids for which BPXA seeks approval uses the terms "includes" and "includes but not limited to." Words such as "includes" and "including" along with phrases such as "includes but is not limited to" inappropriately delegate to BPXA the authority to determine what additional fluids are approved. Therefore, this approval modifies BPXA's proposal to delete the use of any such language as set forth below. In support of its application, BPXA submitted a fluid compatibility review based on previous orders and laboratory testing. This review showed that the proper handling and treating, including the use of scale inhibitors, of the injection fluids as well as the proper operation and maintenance, including the pumping of scale remover and acid treatments, of the injection wells will prevent or counteract incompatibility effects. Thus there are no operational risks associated with injection of the proposed fluids in this pool. It has not been demonstrated that the injection of produced gas or enriched hydrocarbon gas will enhance recovery from this pool. Therefore, BPXA's request to allow gas injection in this pool is denied. The change proposed by BPXA will result in increased production, is based on sound engineering and geotechnical reasons, does not promote waste or jeopardize correlative rights, and will not result in increased risk of fluid movement into freshwater. Correlative rights are protected because all lands subject to these orders have been unitized. Freshwater is protected by the proper design and completion of the wells, ongoing /periodic mechanical integrity evaluation required for all injection wells and review of the offset wells to ensure that they won't act as conduits to fluid movement. NOW THEREFORE IT IS ORDERED THAT: Rule 1 of AIO 20 is repealed and replaced by the following: Rule 1. Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and in the strata defined as those strata which correlate with the strata found in well PBU E -100 between the measured depths of 11662 feet and 11805 AIO 20.002 • • September 4, 2012 Page 3 of 4 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: a) Produced water from Prudhoe Bay Unit processing facilities; b) Non - hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 10 degrees F); c) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti -foams /emulsion breakers; v. Glycols d) Non - hazardous glycols and glycol mixtures; e) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides f) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. In addition administrative approval AIO 20.001, which specified additional authorized fluids, is hereby repealed. DONE at Anchorage, Alaska and dated September 4, 2012. r / i Daniel T. eamount, Jr. J • 1' . . rm . ommissioner AID 20.002 • • September 4, 2012 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within l0 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Thursday, September 06, 2012 1:54 PM To: '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'alaska @petrocalc.com'; 'Anna Raft"; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer'; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Bruce Webb'; 'caunderwood'; 'Claire Caldes'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Harbour; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Scott'; 'David Steingreaber; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'Francis S. Sommer'; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'Gregory Geddes'; 'gspfoff; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen @alaska.gov)'; 'Luke Keller; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark P. Worcester; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike Morgan'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'Paul Mazzolini'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Stephanie Klemmer; 'Steve Moothart (steve.moothart @alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tim Mayers'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; Vicki Irwin'; 'Walter Feather) Williamson Mary J (DNR); 'Yereth Rosen '; 'Aaron Gluzman ; 'Aaron Sorrell'; 'Bruce ' Sullivan'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; Bruno, Jeff J (DNR); Case Su g , , 'Eric Lidji'; 'Erik Opstad'; Franger, James M (DNR); 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Lars Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; OilGas, Division (DNR sponsored); 'Patricia Bettis'; Perrin, Don J (DNR); 'Peter Contreras'; Pexton, Scott R (DNR); 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke'; Ballantine, Tab A (LAW); Bender, Makana K (DOA); 'Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov)'; 'Coiombie, Jody J (DOA) (jody.colombie @aiaska.gov)'; 'Crisp, John H (DOA) (john.crisp @alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies @alaska.gov)'; Ferguson, Victoria L (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov)'; 'Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov)'; 'Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov)'; 'Laasch, Linda K (DOA) (linda.laasch @alaska.gov)'; 'McIver, Bren (DOA) (bren.mciver @alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains @alaska.gov)'; Mumm, Joseph (DOA sponsored); 'Noble, Robert C (DOA) (bob.noble @alaska.gov)'; 'Norman, John K (DOA) (john.norman @alaska.gov)'; 'Okland, Howard D (DOA) (howard.okland @alaska.gov)'; 'Paiadijczuk, Tracie L (DOA) ( tracie .paladijczuk @alaska.gov)'; 'Pasqua), Maria (DOA) (maria.pasqual @alaska.gov)'; 'Regg, James B (DOA) (jim.regg @aiaska.gov)'; 'Roby, David S (DOA) (dave.roby @alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve @alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount @alaska.gov)'; Wallace, Chris D (DOA) Subject: aio20 -002 Midnight Sun Oil Pool Attachments: aio20-002.pdf 9 ! ! Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Circle P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669 -7714 I CL ti P • �,$› ��ys THE STATE Alaska Oil and Gas � ALASKA . Conservation Commission ��h GOVERNOR SEAN PARNELL 333 West Seventh Avenue � Anchorage, Alaska 99501 -3572 ALASY' Main: 907.279.1433 Fax: 907.276.7542 ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 20.002 AMENDED Ms. Alison Cooke UIC Compliance Advisor BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519 -6612 RE: Authorized Fluids for EOR and Pressure Maintenance of the Midnight Sun Oil Pool Dear Ms. Cooke: The Alaska Oil and Gas Conservation Commission has amended the Administrative Approval to correct an error in the description of non - hazardous water based fluids. The correction occurs in two locations and is shown in underlined text below. By letter dated April 30, 2012, BP Exploration (Alaska) Inc. (BPXA) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) administratively amend the following Area Injection Orders (AIO): 3A, 4E, 14A, 20, 22E, 24B, 25A, 26B and 31. BPXA requested the amendments in an effort to standardize the fluids authorized for injection for enhanced recovery and pressure maintenance for the oil pools in the Prudhoe Bay Field. BPXA requested the standardization due to the complexity of managing injection operations for multiple pools, with different lists of authorized fluids, which are served by common production facilities. In accordance with terms set forth below, BPXA's request is partially APPROVED, with a minor change to the wording proposed by BPXA. BPXA's request to inject produced gas and enriched hydrocarbon gas is hereby DENIED. BPXA proposes that AIO No. 14A be modified to approve the following for EOR and pressure maintenance injection. - Produced water and gas; - Enriched hydrocarbon gas; - Non - hazardous water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); - Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the AIO 20.002 Amended • October 9, 2012 Page 2 of 4 produced water stream after oil, gas, and water separation in the facility. Includes but not limited to: o Freeze protection fluids; o Fluids in mixtures of oil sent for hydrocarbon recycle; o Corrosion/scale inhibitor fluids; o Anti- foams /emulsion breakers; o Glycols - Non - hazardous glycols and glycol mixtures; - Fluids that are used for their intended purpose within the oil production process. Includes: o Scavengers; o Biocides - Fluids to monitor or enhance reservoir performance. Includes: o Tracer survey fluids; o Well stimulation fluids; o Reservoir profile modification fluids. As shown above, the list of fluids for which BPXA seeks approval uses the terms "includes" and "includes but not limited to." Words such as "includes" and "including" along with phrases such as "includes but is not limited to" inappropriately delegate to BPXA the authority to determine what additional fluids are approved. Therefore, this approval modifies BPXA's proposal to delete the use of any such language as set forth below. In support of its application, BPXA submitted a fluid compatibility review based on previous orders and laboratory testing. This review showed that the proper handling and treating, including the use of scale inhibitors, of the injection fluids as well as the proper operation and maintenance, including the pumping of scale remover and acid treatments, of the injection wells will prevent or counteract incompatibility effects. Thus there are no operational risks associated with injection of the proposed fluids in this pool. It has not been demonstrated that the injection of produced gas or enriched hydrocarbon gas will enhance recovery from this pool. Therefore, BPXA's request to allow gas injection in this pool is denied. The change proposed by BPXA will result in increased production, is based on sound engineering and geotechnical reasons, does not promote waste or jeopardize correlative rights, and will not result in increased risk of fluid movement into freshwater. Correlative rights are protected because all lands subject to these orders have been unitized. Freshwater is protected by the proper design and completion of the wells, ongoing/periodic mechanical integrity evaluation required for all injection wells and review of the offset wells to ensure that they won't act as conduits to fluid movement. NOW THEREFORE IT IS ORDERED THAT: Rule 1 of AIO 20 is repealed and replaced by the following: AIO 20.002 Amended October 9, 2012 Page 3 of 4 Rule 1. Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and in the strata defined as those strata which correlate with the strata found in well PBU E -100 between the measured depths of 11662 feet and 11805 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: a) Produced water from Prudhoe Bay Unit processing facilities; b) Non - hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); c) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti -foams /emulsion breakers; v. Glycols d) Non - hazardous glycols and glycol mixtures; e) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides f) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. In addition administrative approval AIO 20.001, which specified additional authorized fluids, is hereby repealed. NUNC PRO TUNC September 4, 2012 j, otL gyo DONE at Anchorage, Alaska and dated October 9, 2012. e' t ,� 401 Daniel T. Seamount, Jr. r iii . an Commissioner Com sioner 4 TioN 0° • • AIO 20.002 Amended October 9, 2012 Page 4 of 4 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • • Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston St, Ste. 200 5333 Westheimer, Ste. 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 18th President 40818 St. 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Karl Bernie CIRI e Baker Oil Tools K &K Recycling Inc. Land Department m y g 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 s, AK 99 711 Anchorage, 99503 g ge, AK 9 North Slope Borough Richard Wagner Gordon Severson Planning Department P.O. Box 60868 3201 Westmar Cir. P.O. Box 69 Fairbanks, AK 99706 Anchorage, AK 99508 -4336 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchik, AK 99639 Soldotna, AK 99669 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669 -7714 \c(\(—\2 'C‘C • • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, October 09, 2012 3:39 PM To: '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWelllntegrityCoordinator; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Bruce Webb'; 'caunderwood'; 'Claire Caldes'; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Harbour; 'Dave Matthews'; 'David Boelens'; 'David Duffy'; 'David House'; 'David Scott'; 'David Steingreaber; 'Davide Simeone'; 'ddonkel @cfl.rr.com'; 'Dennis Steffy'; 'Elowe, Kristin'; 'Francis S. Sommer; 'Gary Laughlin'; 'Gary Schultz (gary.schultz @alaska.gov)'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'Gregory Geddes'; 'gspfoff; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeffery B. Jones (jeff.jones @alaska.gov)'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Lastufka'; 'Joe Nicks'; 'John Easton'; 'John Garing'; 'John Spain'; 'Jon Goltz'; Jones, Jeffrey L (GOV); 'Judy Stanek'; 'Julie Houle'; 'Julie Litt le'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (Iaura.gregersen @alaska.gov)'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark P. Worcester'; 'Marguerite kremer (meg.kremer @alaska.gov)'; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mike Morgan'; 'Mike) Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'Paul Mazzolini'; 'Randall Kanady'; 'Randy L. Skillern'; 'Rena Delbridge'; 'Renan Yanish'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Stephanie Klemmer'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Thor Cutler'; 'Tim Mayers'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Vicki Irwin'; 'Walter Featherly'; 'Yereth Rosen'; 'Aaron Gluzman'; 'Aaron Sorrell'; 'Bruce Williams'; Bruno, Jeff J (DNR); 'Casey Sullivan'; 'Dale Hoffman'; 'David Lenig'; 'Donna Vukich'; 'Eric Lidji'; 'Erik Opstad'; Franger, James M (DNR); 'Gary Orr'; 'Graham Smith'; 'Greg Mattson'; Heusser, Heather A (DNR); 'James Rodgers'; 'Jason Bergerson'; 'Jennifer Starck'; 'Jill McLeod'; 'Joe Longo'; King, Kathleen J (DNR); 'Cara Coates'; 'Lois Epstein'; 'Marc Kuck'; 'Marie Steele'; 'Matt Gill'; 'Ostrovsky, Larry Z (DNR)'; 'Patricia Bettis'; Perrin, Don J (DNR); 'Peter Contreras'; Pexton, Scott R (DNR); 'Richard Garrard'; 'Ryan Daniel'; 'Sandra Lemke'; 'Talib Syed'; 'Wayne Wooster'; 'Wendy Wollf; 'William Hutto'; 'William Van Dyke'; Ballantine, Tab A (LAW); Bender, Makana K (DOA); 'Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov)'; 'Colombie, Jody J (DOA) (jody.colombie @alaska.gov)'; 'Crisp, John H (DOA) (john.crisp @alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies @alaska.gov)'; Ferguson, Victoria L (DOA); 'Foerster, Catherine P (DOA) (cathy.foerster @alaska.gov) ,Grimaldi, Louis R (DOA) (Iou.grimaldi @alaska.gov) ,Johnson, Elaine M (DOA) (elaine.johnson @alaska.gov)'; 'Laasch, Linda K (DOA) (Iinda.laasch @alaska.gov)'; 'McIver, Bren (DOA) (bren.mciver @alaska.gov)'; 'McMains, Stephen E (DOA) (steve.mcmains @alaska.gov)'; Mumm, Joseph (DOA sponsored); 'Noble, Robert C (DOA) (bob.noble @alaska.gov)'; 'Norman, John K (DOA) ohn.norman @alaska.gov)'; 'Okland, Howard D (DOA) (howard.okland @alaska.gov)'; 'Paladijczuk, Tracie L (DOA) tracie. aladi'czuk @alaska.go v ) , Pas q ual Maria (DOA) ( maria. as ' 'Regg, James B (DOA) (jim.regg @alaska.gov)'; 'Roby, David S p q ual @ alaska. ov ) ; 9 99 (DOA) (dave.roby @alaska.gov)'; 'Scheve, Charles M (DOA) (chuck.scheve @alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount @alaska.gov)'; Singh, Angela K (DOA); Wallace, Chris D (DOA) Subject: aio20 -002 amended Attachments: aio20 -002 amended.pdf 1 THE STATE "ALASKA GOVERNOR SEAN PARNELL Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.20.003 Katrina Garner Head of Base Management Alaska Reservoir Development BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 Re: Docket Number: AIO- 14-030 Authorized Fluids for FOR and Pressure Maintenance for the Midnight Sun Oil Pool Dear Ms. Garner: By letter dated August 27, 2014, and received by the Alaska Oil and Gas Conservation Commission (AOGCC) on September 2, 2014, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to modify Area Injection Order (AIO) 20.002 to authorize the use of miscible and other hydrocarbon gases to enhance recovery from the Midnight Sun Oil Pool (MSOP), BPXA's request is APPROVED. BPXA proposes to inject miscible injectant, as well as other hydrocarbon gases, into the MSOP to enhance oil recovery from the pool. The MSOP is one of several Kuparuk Formation oil pools in the Prudhoe Bay Unit (PBU). On April 30, 2012, BPXA applied to the AOGCC to have one consistent list of approved fluids for all Prudhoe Bay Unit (PBU) oil pools. On September 4, 2012, the AOGCC issued AIO 20.002 which partially approved this request. Gas injection was not authorized for the MSOP at that time. The Aurora, Borealis, and Pt. McIntyre Oil Pools (collectively Other Kuparuk Oil Pools) within the PBU have all been approved for hydrocarbon gas injection for enhanced recovery purposes. The Other Kuparuk Oil Pools provide good analogues, based on similar rock and fluid properties, for what performance could be expected from gas injection in the MSOP. Miscible injectant water alternating gas (MIWAG) has shown no rock or fluid compatibility issues over decades of operation in the Other Kuparuk Oil Pools and other Kuparuk Formation pools on the North Slope. It is anticipated that ultimate recovery from the MSOP will increase by 3-6% by utilizing a MIWAG recovery mechanism. Rule 9 of AIO 20 allows for administrative amendment of the order 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. MIWAG injection in the Kuparuk Formation has been shown to improve oil recovery and thus will not Area Injection Order 20.003 October 23, 2014 Page 2 of 3 promote waste. The PBU is unitized with equalized ownership throughout the pool, thus no correlative rights would be jeopardized by BPXA's proposed activities. MIWAG injection is a well understood process on the North Slope and is based on sound engineering and geoscience principles. Properly constructed MIWAG injection wells and a proper review of other wellbores in the vicinity of the injection well will ensure that gas will stay in the injection zone . NOW THEREFORE IT IS ORDERED: Rule 1. of AIO 20, as amended by AIO 20.002 is repealed and replaced by the following: Rule 1. Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and in the strata defined as those strata which correlate with the strata found in well PBU E-100 between the measured depths of 11662 feet and 11805 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) Enriched hydrocarbon gas; c) Non -hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); d) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; V. Glycols e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids Area Injection Order 20.003 October 23, 2014 Page 3 of 3 DONE at Anchorage, Alaska and dated October 23, 2014. �Z' Cathy . Foerster Chair, Commissioner Daniel T. Seamount, Jr. Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, October 24, 2014 9:52 AM To: (michael j.nelson@conocophillips.com); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller; Corey Cruse; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAA); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Gary Oskolkosf; George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff; Jacki Rose; Jdarlington Qarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Diane Richmond; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Kair, Michael N (DOA); Konkler, Stacey L (DOA); Loepp, Victoria T (DOA); Mayberry, David J (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K To: (DOA); Skutca, Joseph E (DOA); Wallace, Chris D (DOA) Subject: Area Injection Order 20.003 (Midnight Sun Oil Pool) Attachments: aio20-003.pdf Samantha CarCisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carlisle@alaska.gov. James Gibbs Jack Hakkila Bernie Karl Post Office Box 1597 Post Office Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 Post Office Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. Post Office Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Katrina Garner Head of Base Management Richard Wagner Darwin Waldsmith Alaska Reservoir Development Post Office Box 60868 Post Office Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 Post Office Box 196612 Anchorage, AK 99519-6612 (1) C- CLI--� slz�k�� Angela K. Singh 16 by RECEIVED SEP 0 2 2014 August 27, 2014 a A■VlG BP Exploration (Alaska) Inc. !p'r 900 East Benson Boulevard P. 0. Box 196612 Cathy Foerster, Chair Anchorage, Alaska 99519-6612 Alaska Oil and Gas Conservation Commission (907) 561-5111 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Midnight Sun Oil Pool Area Injection Order 20.002: Modification to Rule 1 Dear Chair Foerster, BP Exploration (Alaska) Inc. (BPXA), operator of the Prudhoe Bay Unit, requests modification of Rule 1 of Area Injection Order No. 20.002 to authorize the use of miscible injectant and other hydrocarbon gases to enhance recovery from the Midnight Sun Oil Pool (MSOP). The proposed language to describe the fluids that may be injected to be consistent with the equivalent AIO 3A- 002 for Prudhoe Oil Pool, AIO 004F.000 for Eastern Operating Area of the Prudhoe, Put River, Lisburne, Pt. McIntyre, West Beach, and Stump Island Oil Pools, AIO 02413.004 for the Prudhoe Bay Field, Borealis Oil Pool, and AIO 022E.002 for the Prudhoe Bay Field, Aurora Oil Pool is (requested new language in bold): a) Produced water and gas from Prudhoe Bay Unit processing facilities b) Enriched hydrocarbon gas c) Non -hazardous water and water based fluids - (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); d) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols; vi. Radioactive tracer survey fluids e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. In Area Injection Order No. 20.002, the Commission denied BPXA's initial request to inject produced gas and enriched hydrocarbon gas in the MSOP because the Commission determined that there was not sufficient evidence that the injection of produced gas or enriched hydrocarbon 1^ ftp; gas would enhance recovery from the MSOP. BPXA submits that there now is sufficient evidence, specifically, successful precedent in similar pools (discussed below), demonstrating that the injection of enriched hydrocarbon gas would enhance recovery from the MSOP, and that reconsideration of the Commission's decision in Order No. 20.002 is therefore warranted. The contemplated MSOP operation is a tertiary recovery project using the enhanced oil recovery (EOR) technique of miscible gas displacement via a water -alternating -gas (WAG) process to increase recoverable oil as being performed in other neighboring Prudhoe Bay Unit Kuparuk Formation oil pools such as Aurora, Borealis and Pt. McIntyre as authorized by the aforementioned AIOs: 004F.000, 024B.004, and 022E.002. In those oil pools the estimated incremental FOR recovery ranged from 3 to 6%. This indicates an FOR potential for MSOP ranging from 1.2 to 3.6 MMBO based on a similar 3 to 6% OOIP range. Miscible Injectant (MI), Feed gas, and Residue gas from the Prudhoe Bay Unit Central Gas Facility or the Lisburne Production Center (LPC) are hydrocarbons with similar components to reservoir fluids in the MSOP and as those injected into Aurora, Borealis and Pt. McIntyre oil pools therefore no compatibility issues are anticipated with the MSOP formation or confining zone. Possible MI injectors are projected to be drilled from the existing Prudhoe Bay Unit P1 Drillsite. Currently, MI is delivered to P1 Drillsite as part of the Pt. McIntyre Miscible Gas Project. At present the plan is for only one MSOP WAG injector with first injection of MI expected to occur around 2Q of 2015. Future injection of either Feed or Residue gas may be an option in the MSOP to aid in recovery of trapped MI for reuse in other pools. Based on the above evidence, BPXA requests that Rule 1 of Area Injection Order No. 20.002 be amended as set forth above to allow the injection of enriched hydrocarbon gas in the MSOP, consistent with the Commission's Area Injection Orders No. AIO 3A-002 for Prudhoe Oil Pool, AIO 004F.000 for Eastern Operating Area of the Prudhoe, Put River, Lisburne, Pt. McIntyre, West Beach, and Stump Island Oil Pools, AIO 02413.004 for the Prudhoe Bay Field, Borealis Oil Pool, and AIO 022E.002 for the Prudhoe Bay Field, Aurora Oil Pool. Should you have any questions regarding this request, please contact James Dean at 564-4668. Sincerely, ¢�J Katrina Garner Head of Base Management Alaska Reservoir Development, BPXA 564-4212 Cc: G. Wong, ExxonMobil Alaska Production Inc. J. Schultz, CPAI P. Ayer, Chevron USA D. Roby, AOGCC K. Smith, DNR S. Digert, BPXA S. Kent, BPXA R. Skillern, BPXA 415 b p • • BP Exploration (Alaska) Inc. P 0. Box 196612 900 E. Benson Boulevard Anchorage, AK 99519 -6612 USA CERTIFIED MAIL # 7011 2970 0003 5821 9955 EC r V April 30, 2012 MAY 0 22 Kathy Foerster, Commissioner AOGCIN Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Prudhoe Bay Field Area Injection Orders, Standardization of Authorized Fluids for EOR and Pressure Maintenance Dear Ms. Foerster, This letter is to request a change to Prudhoe Bay Field (PBF) Area Injection Orders (AIO) to standardize the language in the rule referencing the fluids authorized for injection for enhanced recovery and pressure maintenance. BP Exploration (Alaska) Inc. (BPXA) is requesting this change in order to address the complexity of field operations with multiple pools serviced by common facilities and potential confusion that results from the differing language in the various orders. This proposed change is intended to clarify and document the fluids that are authorized for enhanced oil recovery (EOR) and pressure maintenance injection within the PBF and provide greater compliance assurance for our field operations. A review of AlOs for pools in the PBF indicates that some contain very general language and some are very specific in defining which fluids are authorized for injection. The language defining fluids that may be injected has changed over time in successive versions of some of the orders. For instance, AIO 4 language has changed from "non- hazardous fluids ", to "Class II fluids" to "authorized fluids ". In addition, some fluids have received specific authorization via administrative approvals. The diversity of language and changes over time has resulted in confusion over which fluids are actually authorized for injection. The enclosed list (Attachment A) shows the various PBF pools, AlOs, and a summary of the current rule and /or administrative approvals that authorize fluids that may be injected for purposes of pressure maintenance and enhanced recovery. Also included is a summary of findings regarding the compatibility of fluids authorized for injection. As discussed with your staff, BPXA proposes to standardize the list of authorized fluids for the various pools within the PBF. Attachment B is proposed language for this change. In some pools, additional clarification may be required to capture specific conditions or restrictions contained in current orders. Attachment C is a list of historical fluids injected for EOR and pressure maintenance • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 2 Should you have any questions, or require additional information, please contact me at 564- 4838. Sincerely, Q ■10Nan Coati— Alison Cooke UIC Compliance Advisor Attachments cc: Jim Regg AOGCC Dave Roby AOGCC • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 3 Attachment A Prudhoe Bay Field: fluids specifically authorized for enhanced recovery and pressure maintenance in Area Injection Orders AIO Rule Pool _ Fluids Authorized Compatibility with Formation 3 1 Prudhoe non - hazardous fluids; Area Injection Order Application for PBU WOA Bay AIO 3.03 rinsate (minus FOR and Fluid Disposal Wells: Section I: 1. (West) solids) from cleaning aerial Water: Beaufort Sea water and Produced gas coolers; Sadlerochit water; Compatibility: Water AIO 3.018 filtered and sensitivity tests on core samples showed no chemically treated lake significant problems with formation plugging or water used for hydrotesting clay swelling over the anticipated operating range replacement pipeline of salinities for produced and Beaufort Sea water; segments; 2. Miscible Gas from CGF; Compatibility: Full AIO 3.028 mixtures of glycol compatibility - reinjected into producing zone; 3. and water Produced Gas from Sadlerochit and Sag River reservoirs; Compatibility: Full compatibility - reinjected into producing zone 4E 1 Prudhoe authorized fluids; AIO4D, Finding 12: The main fluid source will be Bay (East) AIO 4C.02 rinsate (minus source water from the Seawater Treatment Plant. Put River solids) from cleaning aerial No significant compatibility issues are anticipated Lisburne gas coolers; between the formation and injected fluid. Pt. AIO 4E.022 filtered and Analyses of core samples from Put River McIntyre chemically treated lake Formation sandstone in Prudhoe Bay West water used for hydrotesting Unit Well 2 -14 demonstrate similar clay mineral Beach replacement pipeline types and proportions as those in Kuparuk River Stump segments for Greater Point Formation reservoirs in adjacent North Slope Island McIntyre; fields. Each of the analog fields has a successful AIO 4E.023 filtered and history of waterflooding and based on these chemically treated lake comparisons the water used for hydrotesting Put River Formation is not anticipated to have replacement pipeline compatibility issues related to seawater injection. segments for Prudhoe Bay AIO4C, Finding 20: Seawater is currently injected Unit fields; in the Pt. McIntyre waterflood. It is possible that AIO 4E.034 mixtures of produced water will be used later in the project. glycol and water Both water sources have previously been approved in Area Injection Order No. 4B Finding 34: Laboratory testing, core analyses and geochemical modeling indicate no significant problems are likely due to clay swelling or in -situ fluid compatibility problems between WBOP and Tertiary formation waters. Finding 35: WBOP waterflood source water from the Sagavanirktok Formation is expected to have excess barium ion which could precipitate barium sulfate scale if mixed with PMOP produced water. WBOP produced water will be inhibited upstream of the commingling point with PMOP fluids to prevent scale precipitation. • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 4 PBU EOA Area Injection Order Application, Section I Enhanced Recovery type of fluid: A. source water - treated seawater; Compatibility: no significant problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated; B. produced water from Flow Stations and LPC; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated; C. Natural Gas and NGL; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated; D. Miscibile Injectant; Compatibility: Fluid is returned to the reservoir from which it was produced, no compatibility problems anticipated. 14A 1 Niakuk produced water from LPC, AIO14A, Finding 7: Injection will utilize either Beaufort seawater, produced or source water. The wells are currently trace amounts of scale configured to allow 60,000 Barrels of Water per inhibitor, corrosion inhibitor, Day ( "BWPD ") total, with a maximum injection of emulsion breakers, other up to 70,000 BWPD. The produced water will be products used in production a mix of Pt. McIntyre, West Beach, North process, stimulation fluids Prudhoe Bay, Lisburne and Niakuk produced water separated through the Lisburne Production Center ( "LPC "), with the majority coming from Pt. McIntyre. Seawater has been injected as well. SEM, XRD and ERD analyses conducted on Niakuk core indicate very low clay content in reservoir intervals. As a result no significant problems with formation plugging or clay swelling due to fluid incompatibilities is expected. Produced water may contain trace amounts of scale inhibitor, corrosion inhibitor, emulsion breakers, and other products used in the production process. 20 1 Midnight fluids appropriate for AIO20 Finding 21: Geochemical model results Sun enhanced recovery; indicate that a combined Tertiary water and AIO 20.001 filtered and connate water is likely to form calcium carbonate chemically treated lake and barium sulfate scale. Similar scale water used for hydrotesting precipitation is anticipated for produced water. replacement pipeline Scale will be controlled with commonly available segments inhibitors. Alaska Oil and Gas Conservation Commission • April 30, 2012 Page 5 22E 10 Aurora produced water, Prince A1022B, Finding 9: The compositions of injection Creek source water *, water and AOP connate water were provided in enriched hydrocarbon gas *, Exhibit IV -4 of the original AIO application. Water immiscible hydrocarbon analysis from the nearby Milne Point Prince gas *, tracer survey fluid, Creek Formation was provided in the April 28, non - hazardous filtered 2003 application for rehearing water from pads and cellars *conditions for authorization are included in the current order 24B 2 Borealis produced water, non- A1024A, Finding 9: As previously approved by hazardous filtered water the Commission, produced water from GC -2 is from pads and cellars, used as the primary water source for Borealis tracer survey fluid, treated injection. Injection performance, core, log and seawater, enriched pressure - buildup analyses indicate no significant hydrocarbon gas *, Prince problems with clay swelling or compatibility with Creek source water; in -situ fluids. BPXA analysis of cores from the AIO 24A.001 filtered and BOP wells indicates relatively low clay content. chemically treated lake Petrographic analysis indicates that clay volumes water used for hydrotesting in the better quality sand sections ( >20 md) are in replacement pipeline the range of 3 - 6 %. Clay volumes increase to segments approximately 6 - 12% in rock 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, having been intermixed with the sand through burrowing. The overall clay composition is a mixture of roughly equal amounts of kaolinite, illite and mixed layer illite /smectite. No chlorite was reported during petrographic analysis. The presence of iron - bearing minerals suggests that *conditions for authorization the use of strong acids should be avoided in are included in the current breakdown treatments, spacers, etc. Water from order the seawater treatment plant has been successfully used for injection within the Kuparuk of the Pt. McIntyre Oil Pool. Geochemical modeling indicates that a combination of GC -2 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 Unit. Miscible gas is a hydrocarbon with similar composition to reservoir fluids in the BOP therefore no compatibility issues are anticipated with the formation or confining zones. The composition of injection water from the Prince Creek aquifer is expected to fall within the range of Well W-400 and MPF -02 produced water • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 6 compositions, less than 10,000 -ppm total dissolved solids. Milne Point Unit F -Pad Prince Creek source water has been injected since 1996 into the Milne Point Kuparuk Reservoir, lithologically similar to the BOP, with no apparent formation damage. A single well chemical tracer test in BOP well L -122 conducted using 640 barrels of Prince Creek Source water did not detect any formation damage. 25A 3 Polaris produced water, tracer AIO 25A, Finding 11: The enriched gas proposed survey fluid, enriched for injection is a hydrocarbon with similar hydrocarbon gas, treated composition to reservoir fluids in the Polaris Oil seawater, non - hazardous Pool and therefore no compatibility issues are filtered water from pads and anticipated. cellars, enriched AIO 25, Finding 12: BPXA provided laboratory hydrocarbon gas; analysis of the injection and produced waters. No AIO 25A.001 filtered and significant compatibility problems are evident chemically treated lake from these analyses. Disposal of PBU produced Y Y p P water used for hydrotesting water within the Ugnu sands has successful) 9 9 successfully replacement pipeline occurred in other parts of the field. segments 26B 3 Orion enriched gas, produced AIO 26A, Finding 11: The enriched gas proposed water, tracer survey fluid, for injection is a hydrocarbon with similar treated seawater, Prince composition to reservoir fluids in the Orion Oil Creek source water, non- Pool and therefore no compatibility issues are hazardous filtered water anticipated. from pads and cellars, non- AIO 26, Finding 11: The composition of produced hazardous filtered lake water will be a mixture of connate water and water employed for injection water, and will change over time hydrotesting pipeline depending on the rate and composition of segments injection water. Based on analyses of Polaris water samples, no significant compatibility problems are expected between connate water and injection water. 31 3 Raven produced water, tracer AIO 31, Finding 14: Water compatibility problems survey fluid, stimulation are not expected because of the successful fluids, source water from history of both sea water and produced water STP, and non - hazardous injection into the Prudhoe Bay Reservoir. No clay water collected from well swelling problems have been seen in the Ivishak house cellars and standing Formation in the Ivishak Participating Area of the ponds. PBU (IPA) with either source water injection or produced water injection. When present, scaling in the Ivishak Formation in the IPA has been limited to calcium carbonate deposition, which has been eliminated with acid treatments and controlled with the use of inhibitors. Minimal problems with formation plugging or clay swelling due to fluid incompatibilities are anticipated. • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 7 Attachment B Proposed Standardized List of Fluids Authorized for Injection in Prudhoe Bay Field Pools Fluids authorized for injection include: • Produced water and gas; • Enriched hydrocarbon gas • Non - Hazardous Water and water based fluids — (includes seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than or equal to 2 or less than or equal to 12.5 and flashpoint greater than 140 degrees F) • Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas and water separation in the facility. Includes but not limited to: • Freeze protection fluids; • Fluids in mixtures of oil sent for hydrocarbon recycle • Corrosion /Scale inhibitor fluids • Anti - foams /emulsion breakers • Glycols • Non - hazardous glycols and glycol mixtures • Fluids that are used for their intended purpose within the oil production process. Includes: • Scavengers; • Biocides • Fluids to monitor or enhance reservoir performance. Includes: • Tracer survey fluids; • Well stimulation fluids • Reservoir profile modification fluids • • Alaska Oil and Gas Conservation Commission April 30, 2012 Page 8 Attachment C Historical Fluids Injected for FOR and Pressure Maintenance: these fluids were authorized and injected under the general descriptions of authorized fluids: AIO 4, 4A, and 4B: Class II fluids; AIO 4C: authorized fluids; AIO 3: non - hazardous fluids Treated Seawater supplied from PBU STP. Contains small amounts of chemicals: coagulant, anti -foam, scale inhibitor, biocide, oxygen scavenger and other process chemicals. Produced water from PB field producing formations. Contains small amounts of entrained produced oil and gas, and chemicals: scale inhibitor, corrosion inhibitor, emulsion breaker, and other production process chemicals. Natural Gas (including natural gas liquids) from PB field producing formations. Miscible lnjectant from PBU Central Gas Facility. Reserve Pit water from pit dewatering operations. Consists of precipitation and small amounts of drilling wastes and chemicals (oxygen scavenger and biocide). Source water from shallow formations. Contains small amount of production chemicals (scale inhibitor). ~14 . . June 20, 2007 Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 West ttb Avenue Anchorage, Alaska 99501 Subject: Hydrotest Water: PBU 2007 Pipeline Replacement Project: Administrative Approval Request: Prudhoe Oil Pool, Area Injection Orders 3 and 4E Midnight sun Oil Pool, Area Injection Order 20 Borealis Oil Pool, Area Injection Order 24A Polaris Oil Pool, Area Injection Order 25A Orion Oil Pool, Area Injection Order 26A Dear Mr. Norman: BP Exploration (Alaska) Inc. (BPXA) requests approval under Area Injection Order (AIO) 4E Rule 9, AIO 3 Rule 9, AIO 20 Rule 9, AIO 24A Rule 8, AIO 25A Rule 13, and AIO 26A, Rule 11 to utilize water from pressure testing (also known as hydrotesting) replacement oil transit pipeline segments as an enhanced oil recovery (EOR) fluid in the various Greater Prudhoe Bay pools listed above. This water will temporarily augment ongoing water injection in the pool by providing additional water volume. During injection, the Class IT disposal wells at FS-3 and GC-l will be shut in to ensure all of the hydrotest water will be utilized for EOR. FS-l to Skid 50 Oil Transit Line Segment Approximately 26,500 feet of 18" pipeline is under construction to replace a section of oil transit pipeline. This line will carry production from the FS-I to Skid 50 and is scheduled for pressure testing before the end of June. Approximately 7700 barrels of treated lake water will be used to pressure test the line. After the pressure test is complete, the hydrotest water will be displaced into a tank and then into pipeline to FS-3, mixing with produced fluids. At FS-3 the water will be separated in the process trains and injected in EOR wells at DS 13 and 14. In this way, the hYdrotest water will augment the current water injection in the Prudhoe Oil Pool. The total volume of produced water injection is about 150,000 bpd, and the dilution of the hydrotest water with produced water will minimize any potential water compatibility issues. GC-2 to GC-l Oil Transit Line Segment Appfûximately 16,200 feet of 20" pipeline is under construction to replace a secíÌon of oil transit pipeline. This line will carry production from GC-2 to GC-l and is scheduled for pressure testing in late June or early July. Approximately 5900 barrels of treated lake Mr. John Norman, Chc.an June 20, 2007 Page 2 . water will be used to pressure test the hne. After the pressure test is complete, the hydro test water will be displaced into a tank and then into pipeline near GC-1, mixing with produced fluids. Depending on the process configuration at the time, the GC-1 water may also be routed to GC-3 then to FS-3. Given the configuration uncertainty, some hydrotest water could be injected in the following pools: Prudhoe, Midnight Sun, Borealis, Polaris, or Orion, at pads E, L, R, D, V, W, Z or DS 13 and 14. ln this \vay, the hydrotest water will augment the current water injection. The total volume of produced water at GC-1 is about 100,000 bpd and the dilution of the hydrotest water with produced water will minimize any potential water compatibility issues In both cases, the lake water will be filtered and treated with a corrosion inhibitor and an oxygen scavenger. At the specified chemical concentrations, the treated lake water will be considered non-hazardous. Alternatives to proposed beneficial use of the hydrotest water include surface discharge after filtration under a NPDES permit, or trucking the water to a suitable disposal site. The difficulty in removing very small particles limits the effectiveness of filtration treatment to meet NPDES effluent limits for turbidity and color. The option of trucking the hydrotest water to Pad 3 would require multiple loads increasing the complexity of the job and the possibility of a spill. We believe the best option for handling the hydrotest water from this replacement pipeline is to use it to augment the GPB waterfloodÆOR project. Additional pipeline replacement projects are in progress or are planned elsewhere in the Greater Prudhoe Bay area, so BPXA may have additional requests to beneficially reuse pipeline hydrotest water at other field locations in the future. Please call me at 564-5229 if you have any questions. Sincerely, / 1 ¡;1 ".? ry2" r ¡^ ¡¡ ~I"c ¡,iJU6'L- Colleen Burgh ' Waste Technical Authority cc: James Regg, AOGCC #13 (~) ~ /~"\ ~~:1 ¡-:; ,,,.J.d 1.1 ;l.\j¡ I; :''';' ! f\ \'1 ¡i ' "-,\\! 'I', \ ,J i? ·1""'1u'·) II! =¡.. [1 ~I Uti w iJ L.:: 1m l~ L~ ~ ~~ ,-1 L(~/Æ FRANK H. MURKOWSKI. GOVERNOR A""A.~KA OIL AlÐ) GAS CONSERVATION COMMISSION 333 W. 7TH AVENUE. SUITE 100 ANCHORAGE, ALASKA 99501·3539 PHONE (907) 279-1433 FAX (907) 276-7542 September 27, 2004 Proposals to Amend Underground Injection Orders to Incorporate Consistent Language Addressing the Mechanical Integrity of Wells The Alaska Oil and Gas Conservation Commission ("Commission"), on its own motion, proposes to amend the rules addressing m~chanical integrity of wells in all existing area injection orders, storage injection orders, enhanced recovery injection orders, and disposal injection orders. There are numerous different versions of wording used for each of the rules that create confusion and inconsistent implementation of well integrity requirements for injection wells when pressure communication or leakage is indicated. In several injection orders, there are no rules addressing requirements for notification and well disposition when a well integrity failure is identified. Wording used for the administrative approval rule in injection orders is similarly inconsistent. The Commission proposes these three rules as replacements in all injection orders: Demonstration of Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and before returning a well to service following a workover affecting mechanical integrity. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30 minute period. The Commission must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone isolation. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. The following table identifies the specific rules affected by the rewrite. Injection Order "Demonstration of Mechanical Integrity" Affected Rules "Well Integrity Failure and Confinement" "Administrati ve Action" Area Injection Orders AIO 1 - Duck Island Unit AIO 2B - Kuparuk River Unit; Kuparuk River, Tabasco, Ugnu, West Sak Fields AIO 3 - Prudhoe Bay Unit; Western Operating Area AIO 4C - Prudhoe Bay Unit; Eastern Operating Area AIO 5 - Trading Bay Unit; McArthur River Field AIO 6 - Granite Point Field; Northern Portion AIO 7 -Middle Ground Shoal; Northern Portion AIO 8 - Middle Ground Shoal; Southern Portion AIO 9 - Middle Ground Shoal; Central Portion AIO lOB - Milne Point Unit; Schrader Bluff, Sag River, Kuparuk River Pools AIO 11 - Granite Point Field; Southern Portion AIO 12 - Trading Bay Field; Southern Portion AIO 13A - Swanson River Unit AIO 14A - Prudhoe Bay Unit; Niakuk Oil Pool AIO 15 - West McArthur 6 7 9 6 7 9 6 7 9 6 7 9 6 6 9 6 7 9 6 7 9 6 7 9 6 7 9 4 5 8 5 6 8 5 6 8 6 7 9 4 5 8 5 6 9 ( (( Affected Rules "Demonstration of "Well Integrity "Administrati ve Injection Order Mechanical Failure and Action~' Integrity" Confinement" River Unit Ala 16 - Kuparuk River 6 7 10 Unit; Tam Oil Pool 6 8 Ala 17 - Badami Unit 5 Ala 18A - Colville River 6 7 11 Unit; Alpine Oil Pool AIO 19 - Duck Island Unit; 5 6 9 Eider Oil Pool AIO 20 - Prudhoe Bay Unit; 5 6 9 Midnight Sun Oil Pool AIO 21 - Kuparuk River 4 No rule 6 Unit; Meltwater Oil Pool AIO 22C - Prudhoe Bay 5 No rule 8 Unit; Aurora Oil Pool 6 9 Ala 23 - Northstar Unit 5 AIO 24 - Prudhoe Bay Unit; 5 No rule 9 Borealis Oil Pool AIO 25 - Prudhoe Bay Unit; 6 8 13 Polaris Oil Pool AIO 26 - Prudhoe Bay Unit; 6 No rule 13 Orion Oil Pool Disposal Injection Orders DIO 1 - Kenai Unit; KU No rule No rule No rule WD-1 DIO 2 - Kenai Unit; KU 14- No rule No rule No rule 4 DIO 3 - Beluga River Gas No rule No rule No rule Field; BR WD-1 DIO 4 - Beaver Creek Unit; No rule No rule No rule BC-2 DIO 5 - Barrow Gas Field; No rule No rule No rule South Barrow #5 DIO 6 - Lewis River Gas No rule No rule 3 Field; WD-1 DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-1 DIO 8 - Beaver Creek Unit; 2 3 5 BC-3 DIO 9 - Kenai Unit; KU 11- 2 3 4 17 DIO 10- Granite Point 2 3 5 Field; GP 44-11 Affected Rules "Demonstration of "Well Integrity " Administrative Injection Order Mechanical Failure and Action" Integrity" Confinement" DIO 11 -Kenai Unit; KU 2 3 4 24-7 DIO 12 - Badami Unit; WD- 2 3 5 1, WD- 2 DIO 13 - North Trading Bay 2 3 6 Unit; S-4 DIO 14 - Houston Gas 2 3 5 Field; Well #3 DIO 15 - North Trading Bay 2 3 Rule not numbered Unit; S-5 DrO 16 - West McArthur 2 3 5 River Unit; WMRU 4D oro 17 - North Cook Inlet 2 3 6 Unit; NCill A-12 oro 19 - Granite Point 6 Field; W. Granite Point State 3 4 17587 #3 OIO 20 - Pioneer Unit; Well 3 4 6 1702-150A WDW 010 21 - Flaxman Island; 3 4 7 Alaska State A-2 OIO 22 - Redoubt Unit; RU 3 No rule 6 01 OIO 23 - Ivan River Unit; No rule No rule 6 IRU 14-31 DIO 24 - Nicolai Creek Order expired Unit; NCU #5 OIO 25 - Sterling Unit; SU 3 4 7 43-9 010 26 - Kustatan Field; 3 4 7 KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, No rule No rule No rule Point McIntyre Field #6 SIO 2A- Swanson River 2 No rule 6 UnÏt;KGSF #1 SIO 3 - Swanson River Unit; 2 No rule 7 KGSF #2 Enhanced Recovery Injection Orders EIO 1 - Prudhoe Bay Unit; No rule 8 Prudhoe Bay Field, Schrader No rule Bluff Fonnation Well V-I05 ~, Injection Order Era 2 - Redoubt Unit; RU-6 "Demonstration 0 f Mechanical Integrity" 5 ~. Affected Rules "Well Integrity Failure and Confinement" 8 "Administrati ve Action" 9 I 02-902 (Rev. 3/94) Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS NOTICE TO PUBLISHER ADVERTISING ORDER NO. INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AO-02514016 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COpy OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE F R o M AOGCC 333 West ih Avenue, Suite 100 Plnchorage,AJ( 99501 907-793-1221 AGENCY CONTACT DATE OF A.a. lody Colombie September 77, 7004 PHONE pcl\¡ (907) 793 -17.71 OATES ADVERTlSEME~T REQL'IRED: T o JournalofConunerce 301 Arctic Slope Ave #350 Anchorage, AJ( 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRL'CTlONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of SS INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COpy OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. ATTACH PROOF OF PUBLICATION HERE. division. Before me, the undersigned, a notary public this day personally appeared who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2004, and thereafter for _ consecutive days, the last publication appearing on the _ day of , 2004, 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 2004, Notary public for state of My commission expires 9/29/2004 1: 10 PM 10f2 Subject: Public Notices From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 29Sep200413:01 :04 -0800 'f():UIlqi~cl()se~-rec.ipi~nts:; . ... ......... .... .......................... ............... ....... ................. . ..................... ................... ...; ..: BeC: Cynthia B Mciver <bren_mciver'@ª~~stÆlt~.~~µs>,.AI1.g~Iª:We9þ................. ................ .......................... <angie ~webb@achnin.state.~.us>, Robert E Mintz . <robert _ m~~~.@1;:t~.~t~!~!~~?";:9~~~ne, Hansen <c.hansen@iogcc.state.ok.us>, Terrie Hubble <hubblet~@bp.cotlîr-;$<mdtâS.t~WtP:à.n: <StewmaSD@BP .com.>, Scott & Cammy Taylor .<staylor@alaska.net>,. stanekj <stanekj.@unocal.com>, ecolaw <ecolaw@tmstees.org>, roseragsdale <roseragsdalè@gci.net>, trmjr 1 <trmjr 1 @aol.com>,jbriddle, <jbriddle@marathonoil.com>, rockhill <roc~ill@aoga.org>, shaneg <shaneg@evergre~ngas.com>, jdarlington <jdarlington@foresto.~~.co:n,t?', nelson <knelsoll@petroleurrin~ws.com>, cboddy <cbóddÿ@tisibelli.com>~ ~arkDaIton. . <mark.dalton@hdrinc.com>,Shannon Donnelly <shannoÌ1.doIll1e1iy@c()nocophillips..com>~. "M. ark P. Worcester" <mark. p.worcester@conOcophillips.eom>, " Jerry C. Dethlefs" . .... "! . '., <jerry.c.dethlefs@conocophillips.com>, Bob <bob@inletkeeper.org>, wdv <wdv@dnr.state.ak.us>, tjr <tjr@dnr.state.ak~us>, bbritch <~britch@â1ask~.nët>, D.1Jnelson <mjne1son@pt1FVÏI1gertz.com>, Charles O'Donnell <chatles.o'donnell@veco.com>, "RandY,L. Skillern" <SkiUeRI-@BP.com>, "Deborah J.Jones" <JonesD6@BP.com>, "Paul G. Hyattrt <hyattpg@BP.com>, "Steven R.Rossberg" <RossbeRS@BP.com>, Lois <lois@inle~eepe¡'.org>, D~ Bro~s.<kuacnews@kuae.org>, Gordon Pospisil <PospisG@BP . com> , "Françis: S. Sommer" <SommerFS@BP~com>, Mikel Schultz <Mike1.Schultz@BP.com>, "NickW. Glover" <GloverNW@BP.com>,· "Daryl.J~ i<.1eppin" <KleppiDE@I3P~com>, "JanetD. Platt" <~lattJD@BP.com>, "Rpsanne M.·Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.IT~com>, . Collins . Mount <collins_ mount@revenue.stiite.ak.us>, nickay <mckay@gci.net>,:Barbara F" Fullmer <barbara~f.fu11mer@cono~ophi~lips.com>, bocastwf <bocastwf@bp"com>, Charles Bark~r : <barker@usgs.gov>"doµg_schultze <doug...:.schultie@xtqeriergy.com>, Hank Alford '. <hank.alfor4@exxonmobil.com>,·MarkKovac <yesno l@gci.net>,gspfoff. .. <gspfoff@aurorappwer.com>, Gregg Nady <gregg.n:ady@shelLcom>~Fred Steeeè . <fred~steece@state.sd.us>,rcrotty <rcrotty@eh2m.com>, j~jQnes <jejones@aurorapower.com>, dé:J,pa <dapa@alaska.net> ,jroderick <jroderiek@gci.net>, eyancy <eyancy@sea1:..tite.net>, "James·M. , , '. . ,'.. . Ruud" <janies.n}.rutid@eonocophillips.com>·, Brit Lively <m~p~aska@alcnet>,jah . <jah@dnr.state.ak:us> , Kurt·E Ol~on <kurt _ olson@leg~$.state.ak.us>, bU()~()j:e <buonoje@b¡:).com>, Mark Hanley<mark_hanley@anadarko.com>, loren~leman <Ioren_letnan@gov.state~ak.us>, Julie Houle <';u1iè_houle@dnr~state.ak~us>, JohnW Katz<jwkatz@sso.org>, SuzanJ Hi~l . <suzan _hill@dec.state.alcus>, tablerk. <tablerk@unocal.cc;>m>, Brady <bradY@fioga.org>, Brian Havelo~k <beh@dnr.state.ak.us>, .bpopp <bpopp@bor{)µ.gh~JcetiaLak. us>,: JimW)rite. <jiinwhite@satx.rr.com>, "JohnS. Hawo~ It <john~s~haworth@exxorimobil.eom> ,marty <mårty@ddndustrial.com>, ghamrnotis <ghaìnm9n~@aol.CQµl>,nriêlean <nncle~@pòbox.a1aska.riet>, ffikm 7200 .<mkrri7200@~oLc()m>, Brimi' GiIl~~pie <itbmg@ua&al~ska.¢du>, ·David LBoelells ·<dboelens@aL.U'ôrapower.~om> ~ Todq I)urkee <TDURKEE@~G .co:m>', Ga.rySþhuItz. :<gary _ schultz@dnr.~tate..aJ.{. us>,. Wa:yne':~ancier <RANCIER@petr()-canaqa.ca>~ Bill Miller <~ill__Miller@iioalaska.çQIn> ,Br~don (}å~on . <bgagnon@brenalaw.com>, Paul Winslow <pmwinsl()w@forestqil.com>, Gtlrty Catron <eatrongr@bJ?~com>, Shaþn~e.Copel~d <cQpelasv@~p.com:>',· Suzanne· AHexan <sallexan@heb.nenergy..com>,·Kristm·Dirks: <kristin ~ dîrks@~.$tate.alcus>,· ~~:ÿneIl Zeman <kjzeman@rµarathonoil.com>, John Tower <JobD..·Tower@eia.döè~.gov>, .Bill.F owle:r: <Bill_ F owler@anadarko.COM>, V ~ughn Swarti <vaughn~swartz@rbccin.éom>~ Scott Cranswick ~I \ Public Notices Public Notices <s~ott.cranswick@II11Ils.goV>,. Brag McKim<ír1ckil1lbs@BP..com> ~~~~~$.£:i!lCltb.èa.~té3.Šh~d .. Noti ceal1q A.ttCtC~m!9n~ .~()i}:~~.B~9JÇq~~êl M:t1.q.~rg:r0l:fnâ. .' 1n;:5ßct::i9:Q. .orders andtne .... Public . Not.ice H~PPy'\l;c,tJ:.IE;Y J9d,Y Colombie '. ........ . .. .....> ... .... ... .... .¡C~l1t¢Î1t~1fyp~: applicatiotl!msword: .iMed:~a.nç~llntegrl~y·prop()~al..dºC.l.·.. ...... .... ........... ......'...........'.............................'.... ........ :........................ ..................:..............:. ............................ ............1:...................... ·.···..··...·.·.ð..·..·.··...·.A.....,.... '..:. : ... . . ......... ..... ..... ...... ...... :€()ntent~Encodmg:.LJase '7 . .... .'_.... '_.' _',,_.~_, . .",..,w____'......,_"'....'_....."."..,_,_~,,,' ,'.......,',....'~.'.'... .... ·....,....._w·_"...".",.....,.~ "', . ." ._.....;_:..,..."..,;.,.,'_.'".A,~___·_;..'"_._.~.;.~_.,,_,; ._.._ ,,.._._' .,._,_,." '... n'... ...,,'..~.__,_~. _.,':.'......~__'_..,.~.~,.. ...,......~.,,'.~..'. ¡ . .. ... ..... .. ... ............. <. . .... ...... ... ..... ..... >< ... ,. '·ii .......: ........... ....... ...... ............. ...........':. .... .. ....:.. ...:............... ... ... ..... .... .... ............. ..:....... ............. ·iContentH1'YP~: appl~cati()f1I'ms"\Vorø Mëchanicalln~egrity ofW.eUsNoticeJiQci C·. ...... ...«~ik. ··.···4.· ! ·ontent..;En¢o(J.log: uase6 , Content-¡-'ype :a.pplìca.tiorIlrnswotd HappyVaUeyl0 _lIearingNotice.doc ,.. c.()I1~ent~Encºdiltg:··.ba~~~4 . "'. '-"" ,'''-_,."." .,,~~,'_" ".."..."._~.~.~.~",'¡"'.~'-:'~_._" ~'N__.""':"~_'_""_~"""_"""~"'~"'_."_' .. ._. _".. ._,.,..'...i..".,~,,-,._.; .._. "..._'''..,:,..,....~ _...,,'_.._. ._..,'_~.,..,~~__,...'_-:.;.._R._.R.;.,"_;......,_.~....:,'.';".....;,,_._..:.._:._.;_._. .__:..'" ... ~__._,~.,:......".'___ .....:..... ,:.__ ~ of 2 9/29/2004 I: 10 PM Public Notice Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Wed, 29Se,p200412:55:26 -0800 To: legal@alaskajôumal.com Please publish the attached Notice on October 3, 2004. Thank you. Jody Colombie Content-Type: applicationlmsword Mechanical Integrity of Wells Notice.doc ' Content-Encoding: base64 Content-Type: applicationlmsword Ad Order form.doc Content-Encoding: base64 1 of 1 9/29/2004 1: 10 PM Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 /'1al/6d /{//~, David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Kelly Valadez Tesoro Refining and Marketing Co, Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,ID 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle. WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage. AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage. AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd.. #44 Anchorage. AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage. AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage. AK 99508-4336 Jack Hakkila PO Box 1 90083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick. AK 99639 James Gibbs PO Box 1597 Soldotna. AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna. AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks. AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks. AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 · [Fwd: Re: Consistent Wording for Injection( .ers - Well Integrity '" Subject: [Fwd: Re: Consistent Wording for Injection Orders - Well Integrity (Revised)] From: John Nonnan·<john_nonnan@admin.state.ak..us> Date: Fri, 01 Oct 2004 11 :09:26 -0800 To: Jogy J. COÎ()Ifibie<jody --" colornbie@ad1ni~.state.ak. us:> more -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Wed, 25 Aug 2004 16:49:40 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:j im regg@admin.state.ak. us CC:dan seamount@admin.state.ak.us, john nonnan@admin.state.ak.us Jim, looks good, but I still think maybe it would be good to include the following sentence or something like it in the well integrity and confinement rule: "The operator shall shut in the well if so directed by the Commissi?n." My thinking is that otherwise, an operator might argue that the Commission can only require the well to be shut in by going through an enforcement action, issuing an order after notice and opportunity for hearing, or meeting the strict requirements for an emergency order under the regulations. The proposed language makes clear that it is a condition of the authorization to inject, that the operator must shut in the well if directed by the Commission after a notification of loss of integrity, etc. »> James Regg <jim regg@admin.state.ak.us> 8/25/2004 3:15:06 PM »> Rob - Thanks for the review; here's a redraft after considering your comments. I have accepted most of the suggested edits; also attached is response to questions you pose (responses are embedded in the comments, using brackets [JBR - ...] to set apart from your questions). Jim Regg Rob Mintz wrote: Jim, I have some questions abQut the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <iim regg@admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing 10f2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection .crs - Well Integrity... - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIO 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions - adopts "Administrative Actions" title (earlier rules used "Administrative Relief'); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting" freshwater", "aquifers", "USDW s"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norrnan@admin.state.us> Commissioner . Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM lFwd: Re: Consistent Wording for Injection ~t rs - Well Integrity... ( Subject: [Fwd: Re: Consistent Wording for Injection Orders - Well Integrity (Revised)] From: John Norman <john_norman@admin.state.ak.us> Date: Fri, 01 Oct 2004 11:08:55 -0800 To: Jody J COlombie<jody_colombie@admin.state..ak.us> please print all and put in file for me to review just prior to hearing on these amendments. thanx -------- Original Message -------- Subject:Re: Consistent Wording for Injection Orders - Well Integrity (Revised) Date:Thu, 19 Aug 2004 15:46:31 -0800 From:Rob Mintz <robert mintz@law.state.ak.us> To:dan seamount@admin.state.ak.us, jim regg@admin.state.ak.us, john norman@admin.state.ak.us Jim, I have some questions about the draft language, which are shown as comments on the first document attached. Based on my current guesses about what the answers will be to my questions, I also have some suggested edits, which are shown as redlines on the second document attached. »> James Regg <jim regg@admin.state.ak.us> 8/17/20044:33:52 PM »> Please delete previous version (email sent 8/9/04); I found another inconsistency in the injection orders regarding well integrity that I have integrated into the proposed fix. Attached is a proposal for consistent language in our injection orders addressing 3 rules related to well integrity: - "Demonstration of Tubing/Casing Annulus Mechanical Integrity" - "Well Integrity Failure" - "Administrative Actions". This proposal includes input from all Sr. staff (except Jack). If you agree with the approach, I'll work with Jody to prepare the public notice. Main points - Demonstration of Tubing/Casing Annulus Mechanical Integrity - standardizes the wording used for mechanical integrity demonstrations, and establishes abililty to grant alternate methods (e.g., temp survey, logging, pressure monitoring in lieu of pressure testing - specific to AIO 2C for Kuparuk, there is wording that is more appropriately included in Well Integrity Failure (i.e., more frequent MITs when communication demonstrated) - establishes more frequent MIT schedule for slurry injection wells (every 2 yrs) which is consistent with our current practice (but not addressed in regulations) Well Integrity Failure - retitles to "Well Integrity Failure and Confinement"; inserted language regarding injection zone integrity (see DIG 25 and 26) - consistent language regardless of type of injection (disposal, EOR, storage); - eliminates requirement for immediate shut in and secure; allows continued injection until Commission requires shut in if there is no threat to freshwater; - eliminates delay in notifying Commission after detect leakage or communication ("i.e., "immediately notify"); - removes language about notifying "other state and federal" agencies; - requires submittal of corrective action plan via 10-403; - requires monthly report of daily injection rate and pressures (tubing and all casing annuli); this is a requirement we currently impose when notified of leak or pressure communication; - notice and action not restricted to leaks above casing shoe as stated in several DIOs Administrative Actions 10[2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection I.. -fS - Well Integrity ... - adopts" Administrative Actions" title (earlier rules used" Administrative Relief"); - consistent language regardless of type of injection (disposal, EOR, storage); - uses "administratively waive or amend" in lieu of terms like "revise", "reissue", etc.; - adds geoscience to "sound engineering principles"; - language is more generic regarding fluid movement out of zone; existing versions mention varying combinations of protecting "freshwater", "aquifers", "USDWs"; "risk of fluid movement"; "fluid escape from disposal zone" Jim Regg John K. Norman <John Norman@admin.state.us> Commissioner Alaska Oil & Gas Conservation Commission . Content-Type: applicationJrnsword Injection Order language - questions.doc Content-Encoding: base64 --..., ,. ,,-_.. --~._--. Content-Type: applicationJrnsword Injection Orders language edits.doc Content-Encoding: base64 20f2 10/2/20044:07 PM ~\ Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, after a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. For slurry injection wells, the tubing/casing annulus must be tested for mechanical integrity every 2 years. The MIT surface pressure must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, must show stabilizing pressure and may not change more than 10% during a 30 minute period. Any alternate means of demonstrating mechanical integrity must be approved by the Commission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement The tubing, casing and packer of an injection well must demonstrate integrity during operation. The operator must immediately notify the Commission and submit a plan of corrective action on Fonn 10-403 for Commission approval whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, or log. If there is no threat to freshwater, injection may continue until the Commission requires the well to be shut in or secured. A monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. Standardized Language for Injection Orders Date: August 17, 2004 Author: Jim Regg Demonstration of Tubing/Casing Annulus Mechanical Inte.grity The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every t\iVO years in the case of a slurry injection \vcll), and before rcturnin.g a \vcIl to service follo,,-yÜJ~aftef a workover affecting mechanical integrity, and at least once every 4 years while actively injecting. FOf slurry injection \veUs, the tubing/casing arululus tnust be tðsted t<.x mechanica.l integrity èvery 2 YeaFS-; Unless an alternate rneans is approved by the COlnnlission, tnechanìcal integrity tllust be demonstrated by a tubin.Q: pressure test using a +he MfF-surface pressure ofmu:.:t be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that fft-1:fSf--shoW;i stabilizing pressure that doesand Inay not change more than 10%- percent during a 30 minute period. --Àft:Y altenlate nleans of dernonstrating Inechanìcal integrity mu~~t be approved by the COlnnlissìon. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Inte,grity Failure and Confinement Except as otherwise provided in this rule, +lhe tubing, casing and packer of an injection well must demonstrate Inaintain integrity during operation. \Vhenever any pressure conlffiunication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, t+he operator tfH±Sf-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval.: whenever any pressure COt1111-lUl1Ícatien, leakage or lack of injèction zone isolation is indicated by injection rate, operating pressure observation, test, survey. or log. The operator shall shut in the wel! if so directed by the Comn1Ìssion. The operator shall shut in the \Nell \vithout a\vaitin,g a response Üorn thç COl1ullission if continued operation would be unsafe or would threaten contamination of freshwaterlf there is no threat to fresl1\vater, injection lllay continue until the COl111nission requires the \vel1 to be shut in or secured. Until corrective action is successfully completed, ^ª monthly report of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating pressure communication or leakage. Administrative Actions Unless notice and public hearing is otherwise required, the Commission may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. r [Fwd: Re: [Fwd: AOGCC Proposed WI Lant .ß for Injectors]] Sub~.ect: [Fwd: Re: [Fwd: AOGCC Proposed WI Language for Injectors]] From: Winton Aubert <winton_aubert@admin.state.ak.us> Date: Thu, 28 Oct 2004 09:48:53 -0800 To: Jo4y.·J.. Colomþie <j()dY~coløinbie@adfu.in~state~áIclls> This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: R~: [Fwd: AOGCC Proposed WI Language for Injectors] Date: Thu, 28 Oct 2004 09:41:55 -0800 From: James Regg <jim regg@admin.state.ak.us> Organization: State of Alaska To: Winton Aubert <winton aubert@admin.state.ak.us> References: <41812422.8080604@admin.state.ak.us> These should be provided to Jody as part of public review record Jim Winton Aubert wrote: FYI. -------- Original Message -------- AOGCC Proposed WI Language for Tue, 19 Oct 2004 13:49:33 -0800 Engel, Harry R <EngeIHR@BP.com> winton aubert@admin.state.ak.us Injectors Subject: Date: From: To: Winton... Here are the comments we discussed. Harry *From: * NSU, ADW Well Integrity Engineer *Sent: * Friday, October 15, 2004 10:43 PM *To: * Rossberg, R Steven; Engel, Harry R; Cismoski, Doug A; NSU, ADW Well Operations Supervisor *Cc: * Mielke, Robert L.; Reeves, Donald F¡ Dube, Anna T¡ NSU, ADW Well Integrity Engineer *Subject: * AOGCC Proposed WI Language for Injectors Hi Guys. John McMullen sent this to us, it's an order proposed by the AOGCC to replace the well integrity related language in the current Area Injection Orders. Listed below are comments, not sure who is coordinating getting these in front of Winton/Jim. Overall, looks okay from an Operations perspective. We do have a few comments, but could live with the current proposed language. Note the proposed public hearing date is November 4. The following language does not reflect what the slope AOGCC inspectors are currently requiring us to do: "The mechanical integrity of an injection well must be demonstrated before injection begins, at least once every four years thereafter (except at least once every two years in the case of a slurry injection well), and * before* ** 1 of 3 10/28/2004 11:09 AM [Fwd: Re: [Fwd: AOGCC Proposed WI Lani ~ for Injectors]] returnj.ng a well to service following a workover affecting mechanical integrity." After a workover, the slope AOGCC inspectors want the well warmed up and on stable injection, then we conduct the AOGCC witnessed MITIA. This language requires the AOGCC witnessed MITIA before starting injection, which we are doing on the rig after the tubing is run. Just trying to keep language consistent with the field practice. If "after" was substituted for "before", it would reflect current AOGCC practices. It would be helpful if the following language required reporting by the "next working day" rather than "immediately", due to weekends, holidays, etc. We like to confer with the APE and get a plan finalized, this may prevent us from doing all the investigating we like to do before talking with the AOGCC. "Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall * immediately* ** notify the Commission" - This section could use some help/wordsmithing: "A monthly report of daily tubing and casing annuli pressures and inj ection 'rates must be provided to the Commission for all injection wells indicating well integrity failure or lack 9f injection ~one isolation." Report content requirements are clear, but it's a little unclear what triggers a well to be included on this monthly report. Is it wells that ·have been reported to the AOGCC, are currently on-line and are going through the Administrative Action process? A proposed re-write would be: "All active injection wells with well integrity failure or la~k of injection zone isolation shall have the following information reported monthly to the Commission: daily tubing and casing annuli pressures, daily injection rates." Requirements for the period between when a well failure is reported and when an administrative action is approved are unclear. This document states "the operator shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403". If we don't plan to do any corrective action, but to pursue an AA, does a 10-403 need to be submitted? The AOGCC has stated they don't consider an AA as "corrective. action". Let me know if you have any questions. Joe -----Original Message----- From: Kleppin, DaLyl J Sent: Wednesday,. September 29, 2004 1:37 PM To: Townsend, Monte Ai Digert, Scott A; Denis, John R (ANC); Miller, Mike E; McMullen, John C Subject: FW: Public Notices FYI -----Original Message----- From: Jody Colombie [ mailto:jody colombie@admin.state.ak.us Sent: Wednesday, September 29, 2004 1:01 PM Subject: Public Notices Please find the attached Notice and Attachment for the proposed amendment of underground injection orders and the Public Notice Happy Valley #10. Jody Colombie «Mechanical Integrity proposal. ZIP» «Mechanical Integrity of Wells Notice.doc» 2 of3 10/28/2004 11 :09 AM #12 ~. 1 2 3 4 :( ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: MIDNIGHT SUN OIL POOL RULES and 5 AREA INJECTION APPLICATION. 6 7 TRANSCRIPT OF PROCEEDINGS 8 Anchorage, Alaska June 21, 2000 9 9:23 o'clock a.m. 10 APPEARANCES: 11 12 13 ( 14 15 16 17 18 19 20 21 22 23 24 25 ( Commissioners: MS. CAMILLE OECHSLI TAYLOR MR. DAN SEAMOUNT * * * * * * t·.t"'~ r;"" .ý',.,~., ~ ~'Y~,~. ¡. "Irf!,'r ~\, . ~ .""t""~,,,,"I'\ ".,'" """"""[.""'''') J I!,. ¡ ...... ~': \') ,';' .'/ ~·IJ:~ .,: ~,(!I ffl.~I':\f:';'" ,r'" JUL 0 6 21.~!C ''¡ A!a~kÐ Œ! &. Gas Cons.. Commission ,Anchorage MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ^ ^ ^ ORIGINAL I v v y ,{ 2 ( 1 PRO C E E DIN G S 2 3 (On record - 9:23 a.m.) 4 COMMISSIONER SEAMOUNT: I would like to call 5 this hearing to order. The date is June 21, 2000. The time is 6 approximately 9:23 a.m. We're located 3001 Porcupine Drive, 7 Anchorage, Alaska. These are the offices of the AOGCC. Start 8 by introducing the head table. My name is Dan Seamount, one of 9 the commissioners. Our other commissioner is -- to my left is 10 Cammy Oechsli Taylor. Laura Ferro of Metro Court Reporting is 11 making a transcript of the proceedings. You can get a copy of 12 transcript from Metro Court Reporting. 13 The purpose of today's hearing is to consider an ( 14 application from Phillips Alaska, Incorporated, to establish 15 pool rules for the Midnight Sun Oil Pool; and also to approve 16 an area injection order authorizing enhanced oil recovery 17 operations in the pool. Notice of the hearing was published on 18 May 10, 2000. It was previously scheduled for June 13, 2000, 19 and it's been continued to today. 20 Start with some ground rules. These proceedings are 21 held in accordance with 2 0 AAC 25.540, regulations governing 22 public hearings. The hearing will be recorded. There should 23 be no off the record conversation except among the applicants 24 themselves or I guess any of the parties themselves. You can 25 do that during the recess or if we have an in camera that's a ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. here and we'll pull a chair in for them if there's too many 25 24 there. So, anyone that wants to ask questions, you can come up 23 when you're testifying, please use the microphone that's up 22 Commission. One other thing, if you have questions, and always 21 invite the applicant to introduce themselves and approach the 20 So, I would like to introduce the -- I would like to 19 questioning. 18 let the person giving -- asking the question do their own 17 questions, go ahead and send them up to me and often we'll just If you have 16 other testimony besides the applicants? Okay. Is there anyone here that's going to be giving any 15 the time. I didn't see -- the sign up sheet wasn't real full at 14 ( 13 will be considered by the commissioners. 12 examination. Those wishing to cross examine the applicants 11 allow you to -- allow other testimony, protest, or cross 10 question. But there is also good possibility that we could 9 forward it to the head table. The Commission will ask the 8 Generally the way to do that is to write your questions, 7 opportunity for other interested parties to ask questions. 6 We'll hear from the applicant first, and then we'll allow 5 will rule on whether to consider you as an expert or not. 4 you should state your qualifications, and then the Commission 3 the sworn testimony. If you wish to be considered an expert, 2 testimony or unsworn statements. Greater weight is given to 1 confidential session. We provide that we can consider sworn ( 3 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. testimony in support of the application to establish pool rules 25 Phillips Alaska is presenting MR. GROTH: 24 23 an expert witness. Please continue. COMMISSIONER SEAMOUNT: We will accept you as 22 21 don/t have any objections. COMMISSIONER OECHSLI TAYLOR: I don/t and I 20 19 questions I Commissioner? COMMISSIONER SEAMOUNT: Do you have any 18 17 witness. 16 effort since 1998. lid like to be recognized as an expert 15 positions. I have supervised the Midnight Sun development 14 Phillips Alaska and its predecessor since 1977 in a variety of ( 13 engineering from Rice University. live been employed by 12 Alaska. I hold a Bachelor of Science degree in chemical MR. GROTH: 11m a supervisor with Phillips I 11 10 represent I Mr. Groth? COMMISSIONER SEAMOUNT: And who do you 9 MR. GROTH: My name is John Groth. 8 COMMISSIONER SEAMOUNT: What is your name? 7 MR. GROTH: Yes I I do. 6 (Oath administered) 5 COMMISSIONER SEAMOUNT: Raise your right hand. 4 MR. GROTH: Yes I I will be. 3 Are you going to be giving sworn testimony? 2 1 people up front I if there/s a lot of people. (' 4 f { :~ 5 (~ 1 for the Midnight Sun Field, and to amend or establish the area 2 injection order for the pool as appropriate. And I'll come 3 back to that shortly. Phillips Alaska presents this testimony 4 on behalf of the Midnight Sun working interest owners: 5 Phillips Alaska, BP Amoco, and Exxon Mobil. The testimony is 6 divided into several parts. Paul Daggett will describe the 7 geologic aspects. Eric Reinbold will describe the reservoir 8 and operations aspects. Dan Eck will describe the facility and 9 allocation aspects. Each witness is prepared to respond to 10 questions concerning his testimony and related exhibits. For 11 the convenience of the Commission, we have available the text 12 of the testimony and copies of the exhibits. 13 In today's testimony, we will elaborate on an alternate ( 14 source of injection water, which was mentioned in our 15 application of May 3rd. Under consideration by the owners is 16 the option to distribute produced water from the GC1 to 17 Midnight Sun for water flow operations. We will discuss this 18 alternative in more detail in the facilities, well operations, 19 and area injection operations portion of the testimony. 20 Phillips Alaska submitted the application for the area 21 injection order and is providing testimony today in support of 22 that application. The Commission however may wish to issue the 23 area injection order with due consideration of the imminent 24 approval of a single operator for the Prudhoe Bay Unit. 25 Unless there are any questions at this time, I'll turn ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER SEAMOUNT: What is the subject? 24 expert witness. 23 team since October 1998. lId like to be recognized today as an 22 positions. lIve been working on the Midnight Sun development 21 its predecessor since 1981 in a variety of geoscience 20 University. I worked for Phillips Alaskal Incorporatedl and 19 doctor of philosophy degree in geophysics from New Mexico State 18 degree in physics from Georgia Institute of Technology and a 17 Phillips Alaskal Incorporated. I received a Bachelor of Scient 16 MR. DAGGETT: Ilm a staff geophysicist with 15 represent? COMMISSIONER SEAMOUNT: And who do you MR. DAGGETT: My name is Paul Daggett. 12 your name? COMMISSIONER SEAMOUNT: No questions. Do you wish to give sworn testimony? MR. DAGGETT: Yes, I do. COMMISSIONER SEAMOUNT: Please raise your right hand. (Oath administered) MR. DAGGETT: I do. COMMISSIONER SEAMOUNT: Thank you. What is 3 questions. COMMISSIONER OECHSLI TAYLOR: I don't have any 1 to Paul Daggett to get us started. 6 f 25 14 (' " 13 11 10 9 8 7 6 5 4 2 ( 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. Exhibit 1-2 shows the location of the Midnight Sun 25 Field did not encounter the Kuparuk River Formation. 24 21 Lake Number 1, Abel State Number 1, Term Well A, North Prudhoe 22 Bay State Number 1 and Number 2, and North Prudhoe Bay Number 3 23 wells, and wells drilled from nearby pads in the Prudhoe Bay 20 encounter the Kuparuk River Formation in this area. The Fawn 19 Kuparuk River Formation. The E-I00 well is the first well to MR. DAGGETT: The reservoir interval is the 18 17 okay? Is that okay? Okay. Sorry. 16 Do we need to close the shades here? Can everybody see that 15 COMMISSIONER SEAMOUNT: Mr. Daggett, excuse me. 14 southwest of the Point McIntyre Pool. ( 13 located north of the Prudhoe bounding fault system and 12 Number 1, later renamed E-I00 well. Midnight Sun Pool is 11 Pool was discovered in 1997 during the drilling of Sambuca 10 North Slope, as illustrated on Exhibit I-I. The Midnight Sun 9 application. The Midnight Sun Pool is located on Alaska's 8 will be on the geology section of the Midnight Sun Pool rules MR. DAGGETT: Thank you. My testimony today 7 6 expert witness. 1 MR. DAGGETT: Geology. 2 COMMISSIONER SEAMOUNT: Do you have any 3 questions, Commissioner? 4 COMMISSIONER OECHSLI TAYLOR: I don't. 5 COMMISSIONER SEAMOUNT: We'll accept you as ( 7 i~ 1(: 8 f 1 Participating Area. Development drilling will utilize the 2 existing gravel E-pad from which the E-100 discovery well was 3 drilled. One delineation well, the Midnight Sun Number 1 well, 4 later renamed E-101, was drilled from the E-pad in October 1998 5 to confirm the extent of the Midnight Sun discovery. 6 The Midnight Sun Pool is composed of the Kuparuk River 7 Formation, also informally referred to as the Kuparuk 8 Formation. This formation was deposited during the Lower 9 Cretaceous geologic time period between 153 and 115 million 10 years before present. 11 Exhibit 1-3 shows a portion of the open hole electric 12 logs from the E-100 well. This type log illustrates the 13 stratigraphic definition of the Midnight Sun Pool. The log is ( 14 scaled in true vertical depth subsea, and also has a measured 15 depth track. In the E-100 well, the top of the Kuparuk 16 Formation occurs at 7,974 feet subsea, or 11,622 feet measured 17 depth, and the base occurs at 8,074 feet subsea or 11,805 feet 18 measured depth. This is also the productive interval of the 19 Midnight Sun Pool. 20 The Kuparuk Formation base is defined by its contact 21 with the Jurassic-age Kingak Formation as seen with a change in 22 lithology and conventional electric log character. The Kingak 23 Formation is a shale with low resistivity of one to three ohm- 24 meters. The Kuparuk Formation is composed of medium to fine 25 grained quartz-rich to glauconitic sandstone with higher MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ~, 'I' ~ 9 (, 1 resistivity of three to 50 ohm-meters. The Kuparuk Formation 2 top is defined by its contact with the Lower Cretaceous age 3 High Radioactive Zone Formation as seen by a change in 4 lithology and conventional electric log character. The HRZ is 5 a black organic-rich shale recognized by the gamma ray log 6 typically greater than 150 gamma API units. 7 The Kuparuk Formation in the Midnight Sun Pool is 8 stratigraphically complex, characterized by rapid change in 9 thickness, sedimentary facies, and local digenetic cementation. 10 Lithology is dominantly sandstone with lesser amounts of 11 siltstone sandy mudstone. As shown on the type log in Exhibit 12 1-3, the Kuparuk Formation can be divided into upper and lower 13 units. The basal portion of the lower unit in E-I0l is a non- ( 14 productive, tight, glauconitic sandstone with minor amounts of 15 shale rip-up clasts. This unit was not encountered in E-IOO 16 and is assumed to be restricted to the area near E-I0l. Moving 17 up in the lower reservoir unit, which is typically about 40 18 feet thick, the lithology changes abruptly to porous, quart- 19 rich sandstone. Grain size is typically very fine to fine- 20 grained and is well sorted. 21 The lithology of the upper unit is variable, including 22 interbedded sandstone with minor amounts of muddy siltstone. 23 The thickness of this interval is variable and ranges from zero 24 to 70 feet. This interval contains glauconite and siderite and 25 is more prone to reductions in porosity and permeability due to ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 .'1' II 10 (~ 1 cementation and compaction. The sands in the upper unit are 2 poorly to well sorted. Intergranular siderite cement is common 3 in the upper unit and plays an important role in determining 4 reservoir quality. Cementation is especially abundant in the 5 lower portion of the upper unit where it degrades reservoir 6 quality. 7 The upper and lower units have distinctly different 8 thickness trends. The lower unit maintains a nearly uniform 9 thickness through the Midnight Sun area suggesting that its 10 deposition predates significant fault movement. In contrast, 11 the thickness and lithology and of the upper unit are variable 12 and have beeri influenced by syn-depositional faulting. 13 Exhibit 1-4 is a structure map on the top of the ( 14 Kuparuk Formation with a contour interval of 20 feet. Top 15 Kuparuk structure in the Midnight Sun area is characterized by 16 a bowl-shaped depression gently dipping to the northeast. The 17 Midnight Sun depression is bounded to the west by the Prudhoe 18 Mid-Field fault, to the south by the Prudhoe bounding fault 19 system, to the north by the Sambuca fault, and to the east by 20 the North Prudhoe structural high. The top of the Kuparuk 21 horizon reaches a structural high to the southwest at 22 approximately 7,789 feet subsea against the Prudhoe bounding 23 fault. The Kuparuk Formation dips eastward to a zero edge 24 against the North Prudhoe high at approximately 8,100 feet 25 subsea. The structural high surrounding the Midnight Sun ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 11 ( 1 accumulation are devoid of Kuparuk Formation rock. Along the 2 axis of the depression¡ the structural dip is less than two 3 degrees down to the northeast. 4 Exhibit 1-5 is an isochore map of the Kuparuk Formation 5 with a contour interval of 10 feet. The Midnight Sun 6 accumulation is a combination structural/stratigraphic trap 7 with isolation assisted by neighboring structural highs that 8 are fault controlled. The controls on Kuparuk Formation 9 thickness are fault movement and erosional truncation. Kuparuk 10 Formation deposition occurred in marine shoreface and deltaic 11 depositional environments. 12 Exhibit 1-6 is a structural cross section along the 13 axis of the Midnight Sun structural depression. This cross (' 14 section illustrates the western and eastern limits of the 15 Midnight Sun Pool. The western limit of the pool is fault 16 controlled by the Prudhoe Mid-Field fault¡ and the eastern 17 boundary is a stratigraphic truncation of the Kuparuk Formation 18 onto the North Prudhoe structural high. 19 Exhibit 1-7 is a north-south structural cross section 20 through the Midnight Sun Pool. This exhibit illustrates the 21 fault-bounded isolation of the Kuparuk Formation on the north 22 by the Sambuca fault¡ and on the south by the Prudhoe bounding 23 fault system. 24 The Midnight Sun Pool gas-oil contact is determined to 25 be at a depth of 8¡010 feet subsea based on Repeat Formation ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. That concludes my prepared testimony. 25 of the Midnight Sun Pool. 24 And Exhibit 1-9 is a gross hydrocarbon distribution map 23 Pool with a contour interval of 10 feet. 22 Exhibit 1-8 is a net sandstone map of the Midnight Sun 21 proposed boundaries of the Midnight Sun Pool. 20 The boundaries of the Midnight Sun PA encompass the 19 Formation forms the trapping mechanism to the east. 18 17 respectively. Stratigraphic truncation of the Kuparuk 14 defined by the juxtaposition of the reservoir against the 15 impermeable Kingak shale across the Prudhoe bounding fault 16 system, Prudhoe Mid-Field fault and Sambuca fault, ( 13 features. To the south, west, and north, the pool limit is 12 is created by a combination of structural and stratigraphic 11 The trap for the oil and gas in the Midnight Sun Pool 10 extent of the heavy oil is uncertain. 9 lower Kuparuk section below 8,107 feet subsea. The aerial 8 Conventional core from the E-101 well contain heavy oil in the 7 gravity was recovered by the RFT at 8,107 feet subsea. 6 E-101 well. A heavy oil sample measuring 10 degrees API 5 contact. Heavy oil was encountered at 8,107 feet subsea in the 2 the Midnight Sun wells. Based on core water saturation data 3 and mercury injection capillary pressure data, the reservoir is 4 interpreted to be significantly above the effective oil-water 1 Tester data. No oil-water contact was identified in either of ( 12 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER SEAMOUNT: Do you have any 25 24 today. 23 1995. I would like to be acknowledge as an expert witness 22 projects in the Greater Point McIntyre area since April of 21 I've worked on Kuparuk Formation satellite and development 20 projects in Alaska and at ARCO's research facility in Texas. 19 since 1985, and have worked on a variety of engineering 18 employed by Phillips and its predecessor, ARCO Alaska in 17 University of Alaska Fairbanks. I was employed and have been 16 Bachelor of Science degree in petroleum engineer from the 15 engineer on the Midnight Sun development project. I received a 14 staff engineer for Phillips. I've been working as a reservoir ( MR. REINBOLD: I represent Phillips Alaska, a 13 12 represent, Mr. Reinbold? COMMISSIONER SEAMOUNT: And who do you 11 MR. REINBOLD: My name is Eric Reinbold. 10 9 state your name. COMMISSIONER SEAMOUNT: Thank you. Please (Oath administered) 3 4 5 please. 6 7 8 MR. REINBOLD: I do. COMMISSIONER SEAMOUNT: Raise your right hand, MR. REINBOLD: Yes, I will. 2 Will you be giving sworn testimony? COMMISSIONER SEAMOUNT: Thank you, Mr. Daggett. 1 (' 13 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. ( 25 again on the E-I00 core data -- E-I0l, excuse me. In the lower 24 for the upper Kuparuk Formation is 200 millidarcies, based 23 interval, the mean porosity is 27.3 percent. Mean permeability 22 lower Kuparuk Formation excluding the non-reservoir basal In the 21 Formation is 20.7 percent based on the E-I0l core data. 20 the Klinkenberg effect. Mean porosity for the upper Kuparuk 19 pressure, and permeability was corrected for gas slippage or 18 permeability measurements were conducted at overburden Porosity and Permeability. Core porosity and 17 16 to construct the Midnight Sun geologic model. 15 used to calibrate the petrophysical log model, which was used 14 mud and low invasion coring techniques. The core data were ( 13 was cored through the entire Kuparuk section with water based 12 well, and E-I0l, or the Midnight Sun Number 1 well. Well E-I0l 11 (sic) well and log data from the E-I00 or Sambuca Number 1 10 for Midnight Sun Pool is based on core data from the E-I00 Rock and Fluid Properties. The reservoir description 9 8 description development planning section of our application. 7 be in three parts. I'll first start with the reservoir MR. REINBOLD: My testimony this morning will 6 5 expert witness. COMMISSIONER SEAMOUNT: You are accepted as an 4 3 questions and I have no objection. COMMISSIONER OECHSLI TAYLOR: I don't have any 2 1 questions? ( 14 15 t. 1 Kuparuk Formation, excluding the non-reservoir basal interval, 2 the mean permeability is 760 millidarcies. The ratio of 3 vertical to horizontal permeability ranges from 0.2 to 1.0 in 4 the upper Kuparuk Formation, and from 0.6 to 1.0 in the lower 5 Kuparuk Formation. 6 Net Pay. Net pay was determined based on visual 7 inspection of the E-101 core in conjunction with review of thin 8 section and routine core analysis data. The Kuparuk Formation 9 in the Midnight Sun Pool has very low clay content, generally 10 less than two percent by volume, and no defined shale sections. 11 In the upper Kuparuk Formation, reservoir volume is reduced by 12 the presence of discontinuous, nodular and banded siderite and ( 13 glauconite. These mineral inclusions were identified visually, 14 and the net to gross ratio was determined based on the ratio of 15 reservoir quality sand to gross rock area exposed on the 16 slabbed core. The net to gross ratio for the upper Kuparuk 17 Formation ranged from 0.25 to 0.72. The lower Kuparuk 18 Formation has negligible glauconite and siderite content, and 19 exhibits a net to gross ratio of approximately 1.0. The non- 20 reservoir basal interval in the lower Kuparuk section is heavily cemented, with a net to gross ratio of zero. Water Saturation. Water saturation data were measured 21 22 23 throughout the Kuparuk Formation interval in the E-101 low 24 invasion core. A chemical tracer confirmed that the core 25 experienced minimal invasion. Water saturation data were ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( ( 21 22 23 24 25 ( f 16 1 corrected for mud filtrate invasion based on the tracer 2 results. Water saturation measurements from the core were then 3 used to calibrate the petrophysical log model. Mean water 4 saturation for the Kuparuk Formation is 26.4 percent based on 5 E-I0l core data. In the lower Kuparuk Formation excluding non- 6 reservoir basal interval, the mean water saturation is 12.6 7 percent. 8 Water saturation data derived from the core and log 9 data were used to develop Leverett J-functions, which were 10 subsequently translated to drainage capillary pressure curves 11 for the upper and lower Kuparuk Formation intervals. The 12 capillary pressure data were then used to initialize water 13 saturation in the reservoir model based on capillary pressure 14 equilibrium. 15 Relative permeability. A steady state water-oil 16 relative permeability experiment was conducted on a composite 17 core from the upper Kuparuk Formation interval. The residual 18 oil saturation from this displacement experiment was 22.7 19 percent. Centrifuge water-oil and gas-oil experiments were 20 also conducted. Results from these experiments indicate that water-oil relative permeability measurements for the Midnight Sun Pool are similar to those measured for other North Slope fields exhibiting favorable waterflood performance. In the absence of having an extensive data set for all relative permeability functions, analog data sets were used for MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 I~ ~ 17 ( 1 performance projections. 2 Initial Pressure and Temperature. Based on RFT datal 3 the initial reservoir pressure is estimated at 4/058 psia at 4 the reservoir datum of 8/050 feet tvd subsea. The reservoir 5 temperature is approximately 160 degrees Fahrenheit at the 6 datum. 7 Fluid PVT Data. Reservoir fluid PVT studies were 8 conducted on a recombined surface sample obtained from E-I0l 9 well. The sample was recombined to the bubble point pressure 10 of 4/045 psi corresponding to the pressure at the gas-oil 11 contact at initial conditions. The API gravity of the PVT 12 sample was 25.5 degrees I with a solution GOR of 717 standard 13 cubic feet per stock tank barrel I a formation volume factor of (' 14 1.33 reservoir barrels per stock tank barrel I and an oil 15 viscosity of 1.68 centipoise at the bubble point pressure. 16 Exhibit 11-1 shows a summary of the fluid property 17 information for the Midnight Sun Pool. 18 Exhibit 11-2 contains a listing of the various 19 pressure-volume-temperature or PVT properties as a function of 20 pressure. 21 Hydrocarbons in Place. The estimates of hydrocarbons 22 in place for the Midnight Sun Pool reflect current well 23 control I stratigraphic and structural interpretationl and rock 24 and fluid properties. These data were integrated in the 25 construction of a fine scale geologic model I which provides the ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 18 ( 1 basis for estimation of original oil in place. The results 2 indicate an original oil in place range of 40 to 60 million 3 stock tank barrels, and total gas in place of 100 to 130 4 billion cubic feet. The free gas volume associated with the 5 gas cap is 60 to 80 billion cubic feet. 6 Reservoir Performance. Two wells, E-100 and E-101, 7 have been drilled and completed in the Kuparuk Formation. Both 8 wells are tied into the Prudhoe Bay E-pad facilities. 9 Production commenced in October of 1998. 10 Well E-100, the discovery well, encountered 100 feet of 11 gross hydrocarbon column, with 36 feet of gas above oil. The 12 well was perforated over a 20 foot interval at the base of the 13 reservoir. The initial production rate 2/000 to 3/000 barrels ( 14 of oil per day with a GOR of approximately 950 standard cubic 15 feet per stock tank barrel. The rate was restricted to 16 mitigate coning, although the GOR increased steadily to 6/000 17 standard cubic feet per stock tank barrel during the first 18 three months of production. The well is currently shut in to 19 limit reservoir voidage. 20 Well E-101 was drilled as a downstructure delineation 21 well to the Midnight Sun Pool. The well encountered 84 feet of 22 gross hydrocarbon column, all above the gas-oil contact 23 identified in the E-100 well. No oil-water contact was 24 identified by open-hole logs. The initial production rate in 25 November of 1998 was seven to 8/000 barrels of oil per day with ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 19 ( 1 a GOR of approximately 800 standard cubic feet per stock tank 2 barrel. In January of 1999/ the well was restricted to 5/000 3 barrels of oil per day to conserve reservoir energy while 4 completing reservoir surveillance and field development 5 studies. 6 Gas Coning. Production from E-I00 well is affected by 7 gas coning. E-I00 is a deviated well with an inclination of 46 8 degrees across the Kuparuk. The well is completed with a 9 standoff of 42 tvd from the gas-oil contact. During the first 10 10 days of production, the GOR in E-I00 well increased to 2/000 11 standard cubic feet per stock tank barrel. The production rate 12 was restricted to mitigate coning. The cement bond log in this 13 well is interpreted to show good cement quality, and the coning ( 14 interpretation was confirmed by production logging. Subsequent 15 inspection of the E-I00 core E-I0l core confirmed that 16 intra-formation cementation in the upper Kuparuk would act as a 17 baffle but not a barrier to vertical flow. With slightly more 18 than 50 percent of the oil column overlain by the gas cap, 19 coning can be a significant reservoir mechanism in the Midnight 20 Sun Pool. 21 Gas Under-Running. The Midnight Sun reservoir is a 22 thin reservoir with a structural dip of less than two degrees. 23 The low structural relief results in a gas cap that overlays 24 more than 50 percent of the areal extent of the oil column. 25 Reservoir model results calibrated to field performance ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 20 ;( 1 suggest that gas under-running, which is movement of gas below 2 a barrier, will impact early field performance, and is a 3 mechanism to address in depletion planning. The GOR at the 4 well E-I0l is currently over 5,000 standard cubic feet per 5 stock tank barrel and increasing consistent with predictions. 6 The low structural relief at the Midnight Sun reservoir limits 7 the effectiveness of gas cap expansion or gas injection as a 8 recovery mechanism. 9 Development Plans. The reservoir model of the Midnight 10 Sun Pool was constructed to evaluate development options, 11 investigate reservoir management practices, and generate rate 12 profiles for facility design. This section of the application 13 describes the reservoir model, model results, and development ( 14 plans. 15 Reservoir Model Construction. A fine scale three- 16 dimensional geologic model of the Midnight Sun Pool was 17 constructed based on detailed stratigraphic and structural 18 interpretation. This model provided the bulk reservoir volume 19 and distribution of porosity and permeability used in the 20 construction of the Midnight Sun reservoir model. The 21 reservoir model is a three-dimensional three-phase black oil 22 finite different flow simulation model. The model area 23 encompasses the graben fault block defining the Midnight Sun 24 Pool. Areal gridding is 250 feet by 250 feet or 1.43 acre 25 cells. The vertical gridding is defined by 15 model layers ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 21 :(" 1 with nominal thickness of four to eight feet. 2 Exhibit 11-3 shows the average physical properties for 3 each model layer. Faults and juxtaposition are honored through 4 corner point geometry and non-local grid connections. 5 Water saturation in the reservoir model was established 6 by capillary pressure equilibrium. There is no aquifer in the 7 reservoir model. Capillary pressure measurements suggest that 8 the effective oil-water contact is below the structural limit 9 of the reservoir. The 10 at the gas-oil contact 11 RFT data. reservoir pressure was set to 4,045 psi of 8,010 feet tvd subsea based on the 12 Exhibit 11-4 shows the comparison of model predictions 13 and field performance. For the history match, oil rate is ( 14 specified and the reservoir pressure and well GORs are 15 predicted. The history match of reservoir pressure was 16 achieved with no modification to the gas cap volume in the 17 reservoir model. The GOR history match reflects accurate 18 modeling of both the coning at well E-I00 and under-running at 19 well E-I0l, reservoir mechanisms. The downstructure pore 20 volume was increased to reflect under-run timing at well E-I0l. 21 Model Results. Three development options were 22 evaluated for the Midnight Sun Pool: primary depletion, 23 upstructure gas injection, and waterflood. 24 Primary Recovery. Primary recovery was evaluated with 25 E-I0l well as the single downstructure producer. The primary ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 l' 22 ( 1 recovery mechanism was a combination of gas cap expansion and 2 solution gas drive. The gas cap at Midnight Sun contains 3 approximately 40 percent of the total reservoir hydrocarbon 4 pore volume. 5 Model results indicate that primary depletion would 6 achieve an estimated 14 percent recovery of the original oil in 7 place or OOIP. 8 Exhibit 11-5 shows production and recovery profiles for 9 primary depletion. The performance is attributed to depletion 10 of the gas cap and associated reduction in reservoir energy. 11 The model shows gas under-running and high GaR production at 12 well E-101. Reservoir pressure was depleted at the end of the 13 model run, and the majority of the gas cap volume had been ( 14 produced. 15 Upstructure Gas Injection. Upstructure gas injection 16 was evaluated with a horizontal injection well installed in the 17 Midnight Sun gas cap. Reservoir management for this case 18 assumed that injection would be sufficient to increase 19 reservoir pressure back to the original condition and then 20 maintain a voidage replacement ratio of 1.0. The peak 21 injection requirement for this case was 40 million standard 22 cubic feet per day. 23 Model results indicate that upstructure gas injection 24 would achieve an estimated 20 percent recovery of the OOIP 25 after 1.0 hydrocarbon pore volume injection or HCPVI. Recovery { \ MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 23 ( 1 of 27 percent was obtained with 2.0 HCPVI. 2 Exhibit 11-6 shows production and recovery profiles for 3 upstructure gas injection. Upstructure gas injection results 4 in gas under-running the top Kuparuk Formation and then coning 5 into the perforations at the downstructure producer. As a 6 result of these mechanisms, the vertical sweep efficiency for 7 upstructure gas injection is poor with correspondingly low 8 recovery in the lower Kuparuk Formation. 9 Waterflood. Several waterflood development options 10 were studies using the Midnight Sun reservoir model, including 11 upstructure, downstructure, and midfield water injection. Both 12 upstructure and midfield options involve water injection at or 13 near the original gas cap. All waterflood options result in ( 14 some degree of re-saturation of the gas cap by oil in the 15 midfield area. Case studies of successful applications of this 16 type of waterflood process are documented in the literature. 17 The midfield configuration shows the best overall 18 waterflood performance with greater ultimate recovery and an 19 earlier production profile associated with improved pressure 20 response relative to the other cases. Midfield configuration 21 involves conversion of the E-100 well to injection service. 22 Initial production was from the E-101 well. An upstructure 23 horizontal production well is completed two to 4/000 feet east 24 of the western limit of the light oil column. This well was 25 managed in the reservoir model to limit gas coning. ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 24 (I 1 The midfield waterflood shows improved waterflood 2 response over the upstructure and downstructure injection 3 options as evidenced by lower peak GOR and faster pressure 4 response. Waterflood fill-up is achieved within two years of 5 waterflood start up. The improved response is attributed to 6 closer injector/producer spacing and greater distance of the 7 key production well from the gas cap. The midfield water 8 injection case achieves an estimated 39 percent recovery at 0.7 9 HCPV1. Cumulative gas production is lower relative to the 10 upstructure gas injection case. 11 Exhibit 11-8 shows production and recovery profiles for 12 midfield water injection. 13 The upstructure configuration included a new horizontal ( 14 injection well towards the western limit of the light oil 15 column. The configuration was envisioned as a means of 16 isolating the gas cap while waterflooding the midfield and 17 downstructure areas. The primary downstructure producer would 18 be well E-I0l, although the E-I00 well was also produced for a 19 limited time. Model results for upstructure water injection 20 indicate that the western limit of the gas cap can be isolated, 21 and the classic waterflood fill up and response are achieved 22 within three years of waterflood start up. The upstructure 23 water injection case achieves an estimated 39 percent recovery 24 at 0.7 HCPV1, although production response to waterflood is 25 slower and gas production is greater relative to the midfield ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 î' 25 ( 1 case. 2 The downstructure configuration involves conversion of 3 well E-I0l to injection service. Production from well E-IOO 4 would be resumed and rate would be initially restricted to 5 mitigate coning. The downstructure waterflood configuration or 6 in the downstructure waterflood configuration an upstructure 7 horizontal production well is drilled to recover the 8 upstructure reserves. Waterflood performance for downstructure 9 injection is less attractive than the waterflood 10 configurations. In this configuration, gas coning and under- 11 running at well E-I00 require restricted field rate and 12 continue to be a production issue for both production wells. 13 The downstructure water injection case achieves an estimated 31 ( 14 percent recovery at 0.56 HCPVI with a delayed production 15 profile relative to the upstructure and midfield alternatives. 16 Enhanced Oil Recovery or EaR. Preliminary analysis 17 indicates there may be potential for enriched gas injection at 18 Midnight Sun. However, no EaR project evaluations have been 19 initiated. Due to the technical complexities, reservoir 20 uncertainty, and cost involved, improved reservoir description 21 and additional field performance data are necessary before 22 these options may be fully evaluated. . . 23 Development Plans. Based on reservoir model studies, 24 the recommended development plan is implementation of a 25 midfield waterflood for the Midnight Sun Pool. This plan ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 26 ( 1 provides the most favorable production profile while minimizing 2 cumulative gas production and maximizing ultimate recovery. 3 Water injection is expected to commence in the third quarter of 4 2000, with design injection rates of 20 to 25,000 barrels of 5 water per day. A peak production rate of eight to 10,000 6 barrels oil per day is expected prior to waterflood 7 breakthrough. 8 Waterflood Sensitivity Studies. Reservoir model 9 sensitivity studies were conducted in support of development 10 planning. Model runs were conducted to optimize well placement 11 and completion design. Sensitivities to key model assumptions 12 including relative permeability, vertical permeability, and oil 13 viscosity were evaluated. None of these assumptions were found ( 14 to significantly alter development plans. 15 Other sensitivity studies included the effect of 16 continued production to waterflood startup. Earlier waterflood 17 startup mitigates reservoir pressure decline and reduces peak 18 GOR response prior to waterflood fill up. However, no recovery 19 impact was identified with a waterflood startup during the 20 third quarter of 2000, assuming continued production of 5,000 21 barrels oil per day until start up. In the reservoir model, 22 reservoir pressure declined to 3,300 psi, and GOR peaked at 23 8,000 standard cubic feet per stock tank barrel. 24 Well Spacing. The planned development well program 25 includes the addition of one upstructure horizontal production ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 27 ~I 1 well to complete a three well development of the Midnight Sun 2 Pool. The development will form an irregular pattern due to 3 the constraints of development within a small fault block. 4 This well spacing is nominally 280 acres. Closer well spacing 5 does not appear to be justified due to the thin oil column. 6 However, infill drilling and/or peripheral drilling along the 7 eastern margin field may be evaluated as field development 8 continues. To allow for flexibility to respond to these 9 conditions, a minimum well spacing of 80 acres is requested. 10 Reservoir Management Strategy. Gas cap expansion will 11 provide initial pressure support prior to waterflood start up. 12 Following waterflood start up, the VRR or voidage replacement 13 ratio target will exceed 1.0 to suppress gas production and (' 14 restore reservoir pressure. A balanced VRR will be maintained 15 restored once reservoir pressure is restored to a target range 16 of 3,800 to 4,000 psi. 17 In the planned waterflood configuration, oil flux into 18 the gas cap is anticipated in the midfield area due to low 19 structural relief. Reservoir surveillance and voidage 20 management, however, should minimize oil flux to the west of 21 the upstructure horizontal producer. 22 The objective of the Midnight Sun reservoir management 23 strategy is to manage reservoir development and depletion to 24 achieve the maximum ultimate recovery consistent with good oil 25 field engineering practices. To accomplish this objective, ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 28 ( 1 reservoir management is approached as a dynamic process. The 2 initial strategy is derived from model studies and limited 3 historical performance. New well results and additional 4 reservoir performance data will increase knowledge and improve 5 predictive capabilities resulting in adjustments to the initial 6 strategy. The reservoir management strategy for the Midnight 7 Sun Pool will continue to be evaluated throughout field life. 8 Reservoir Performance Conclusions. Reservoir model 9 results support implementation of waterflood in the Midnight 10 Sun Pool. An initial three well development program is 11 contemplated with midfield water injection at well E-100, and 12 the addition of one upstructure horizontal producer. Water 13 injection is expected to commence in the third quarter of 2000, ( 14 with design injection rates of 20 to 25,000 barrels of water 15 per day. Following initiation of waterflood a peak production 16 rate of eight to 10,000 barrels of oil per day is expected. We 17 request that the operator be allowed to determine the field 18 off-take rate based upon sound reservoir management practices. 19 This concludes my testimony on reservoir description 20 and development planning. 21 COMMISSIONER SEAMOUNT: Thank you, Mr. 22 Reinbold. I have a few questions. When -- what date was the 23 E-100 drilled and completed? 24 MR. REINBOLD: I believe it was November of 25 , 97 . ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. you will produce no water ever, correct? 25 COMMISSIONER SEAMOUNT: Now, with gas injection 24 23 plans. 22 the Ivishak is marginal and there are currently no development MR. REINBOLD: At this point, it appears that 21 20 development plans for the Ivishak? COMMISSIONER SEAMOUNT: Do you have any 19 18 up beyond 30 or 40 percent. 17 cut came in initially very low but in order of a few days moved 16 but it was on the order of 3,000 barrels oil per day. Water MR. REINBOLD: I don't know the exact numbers 15 14 were the results of the test? ( COMMISSIONER SEAMOUNT: What was the -- what 13 12 than two years old so no. MR. REINBOLD: I would expect not. It's more 11 10 confidential? COMMISSIONER SEAMOUNT: Is the information 9 MR. REINBOLD: The Ivishak was tested. 8 7 Ivishak? COMMISSIONER SEAMOUNT: Did you test the 6 5 didn't penetrate the base Ivishak. 4 Ivishak. It TD'd below the Ivishak or in the Ivishak. We MR. REINBOLD: It went through the Sag and 3 2 deepest penetration of that well? '97. What was the COMMISSIONER SEAMOUNT: 1 t 29 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER SEAMOUNT: Do you believe that 25 24 top of the heavy oil section. 23 recovered 10 api oil at near the top of the section, near the MR. REINBOLD: We took one sample with RFT and 22 21 What is the gravity of the heavy oil? COMMISSIONER SEAMOUNT: No water in the system. 20 MR. REINBOLD: Fully saturated the tank. 19 COMMISSIONER SEAMOUNT: So..... 18 17 system filled up, it displaced all the water out of the system. MR. REINBOLD: I would expect that as the 16 15 at all? 14 from entering? Is it the heavy oil column or is there no water ( COMMISSIONER SEAMOUNT: What prevents water 13 12 best of our knowledge. COMMISSIONER SEAMOUNT: No. Yeah, in the 8 9 Kuparuk? 10 11 Kuparuk. There's connate water only in the reservoir to the MR. REINBOLD: There's no water leg in the MR. REINBOLD: In the Kuparuk? 7 6 water in the system? COMMISSIONER SEAMOUNT: Do you believe there's 5 MR. REINBOLD: Yeah, connate water, yeah. 4 3 gas injection. COMMISSIONER SEAMOUNT: If you were to go with 2 MR. REINBOLD: Other than just minimal..... 1 ( 30 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. { MR. REINBOLD: We'll speak briefly to that in 25 24 for your team? 23 more of the future drilling plans or did you cover all of it 22 see. You mentioned the future -- are we going to cover the COMMISSIONER SEAMOUNT: Speculative. Let's 21 20 guess I can't answer that question. MR. REINBOLD: That would be speculative. I 19 18 in the future any plans to try to recover any of the heavy oil? COMMISSIONER SEAMOUNT: Would there be possible 17 MR. REINBOLD: No. 16 15 it's moveable at Midnight Sun? COMMISSIONER SEAMOUNT: But you don't believe 14 ( 13 other fields. MR. REINBOLD: I'm not really here to address 12 11 engineering to it? 10 heavy oil moveable anywhere other than if you apply special 9 ignorance, not having much experience on North Slope but is the COMMISSIONER SEAMOUNT: I'm speaking out of 8 7 heavy oil is commercially recoverable. 6 development of only the light oil. We don't expect that the MR. REINBOLD: The development plan calls for 5 4 the light oil in the model? 3 you going to produce some heavy oil? Or did you just consider 2 already in your testimony but is there heavy oil moveable? Are 1 it -- I may not have heard -- you may have answered this (C 31 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276~3876 -( MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER SEAMOUNT: So, the horizontal 25 24 of that up in here. 23 The western limit of the gas cap is just slightly to the west 22 would add an up structure horizontal producer up in this area. 21 January 1999 will become our water injection well, and then we 20 case. The E-I00 well which has been shut in since about 19 the downstructure production well and our midfield development MR. REINBOLD: This is the E-I0l well. That's 18 17 this, guaranteed. 16 space is going to contain a much friendlier hearing room than COMMISSIONER SEAMOUNT: Uh-hum. Our new office 15 14 geologic map. ( 13 can show the overhead. I can show you where they're at on the MR. REINBOLD: I don't have one with me. We 12 11 map with the well locations on it? COMMISSIONER SEAMOUNT: Are you going to show a 10 MR. REINBOLD: In the base plan, yes. 9 8 wells at this time? COMMISSIONER SEAMOUNT: So, you mentioned three 7 6 on reservoir performance and continuing evaluation. 5 drilling in the pool for development purposes, again, depending 4 source water plan. There's also some potential for additional 3 potential of drilling a couple of source wells if we pursue the 2 upstructure producer. We also will make some reference to the 1 the well operation section but at this point we plan one ( 32 ,/ ~ 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 (Oath administered) 22 23 hand. 24 25 ( MET ROC 0 U R T R E P 0 R TIN G, INC. MR. ECK: Yes, I do. COMMISSIONER SEAMOUNT: Please raise your right MR. ECK: Yes, I am. 21 20 testimony? COMMISSIONER SEAMOUNT: Are you giving sworn 19 18 now to Dan Eck who will describe the Midnight Sun facilities. MR. REINBOLD: Thank you. I'll turn it over 17 COMMISSIONER SEAMOUNT: Very good work. 16 MR. REINBOLD: Thank you. 15 14 Reinbold. ( 13 other questions, we'll wait toward the end. Thank you, Mr. COMMISSIONER SEAMOUNT: I guess if there's any 12 11 any questions. Thank you. COMMISSIONER OECHSLI TAYLOR: No, I don't have 10 9 Commissioner? 8 minimum spacing of 80 acres. Do you have any questions, COMMISSIONER SEAMOUNT: Section 36. Okay. And 7 MR. REINBOLD: Section 36. 6 5 northwest corner of the southern section of the field. COMMISSIONER SEAMOUNT: Looks like the 4 MR. REINBOLD: No. 3 2 sections on there. Do you know what section that is? 1 would be in the northwest corner of section -- I don't see ( 33 1\ 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. ( MR. ECK: Midnight S- --..... 25 COMMISSIONER OECHSLI TAYLOR: I don't. 24 23 questions, Commissioner Oechsli? Do you have any COMMISSIONER SEAMOUNT: 22 21 acknowledged as an expert witness today. 20 engineer with the State of Alaska. I would like to be 19 facilities for the past 15 years. I am a registered mechanical 18 design, construction, and operation of hydrocarbon processing 17 subsequently Phillips Alaska, and have been involved in the 16 engineering. Following graduation, I went to work for ARCO, 15 Missouri Rolla with a bachelor degree in mechanical 14 production facilities. I graduated from the University of ( 13 Alaska for the integrity and the viability of the Midnight Sun 12 the Midnight Sun facility engineer responsible to Phillips MR. ECK: Facilities for Midnight Sun. I am 11 What is the subject? COMMISSIONER SEAMOUNT: 10 MR. ECK: Yes, I do. 9 8 considered as an expert witness? MR. ECK: Phillips Alaska. COMMISSIONER SEAMOUNT: And do you wish to be 7 6 5 represent, Mr. Eck? COMMISSIONER SEAMOUNT: And who do you 4 MR. ECK: My name is Dan Eck. 3 2 state your name. COMMISSIONER SEAMOUNT: Thank you. Please 1 (' 34 ii' ~ ,.¡" \~ 35 f: 1 COMMISSIONER SEAMOUNT: We will consider you as 2 an expert witness. Accepted. 3 MR. ECK: Midnight Sun Facilities General 4 Overview. Midnight Sun wells will be drilled from the E-pad 5 drill site. Surface facilities include an existing 1PA drill 6 site, pipelines and processing facilities to produce Midnight 7 reservoir fluids. Midnight Sun fluids will be commingled with 8 Initial Participating Area, IPA, fluids for the surface -- on 9 the surface at E-pad and then transported to Gathering Center 1 10 for treatment and shipment to Pump Station 1. Midnight Sun 11 will make use of existing IPA infrastructure. This minimizes 12 environmental impacts and reduces cost to help maximize 13 recovery. ( 14 Use of 15 and processing the GCl production facility includes separating equipment, inlet manifold and related piping, 16 flare system, and water injection facilities. IPA facilities 17 that will be used include 24 inch low pressure common line from 18 E-pad to GC1, 16 inch and 6 inch high pressure common lines 19 from E-pad to GC1, oil sales line from GCl to pump station I, 20 and the power distribution and generation facilities. Plans to 21 deliver GC1 produced water to E-pad using an existing six inch 22 IPA flowline are also being considered. Exhibit 111-1 is an 23 area map showing locations of the facilities that will be used 24 for Midnight Sun development. 25 Drill Sites, Pads, and Roads. Use of the E-pad drill (" METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276~3876 , ( It 36 ( 1 site for the Midnight Sun wells has been selected to eliminate 2 new gravel placement, minimize well stepout to within current 3 available drilling technology while reaching the extent of the 4 reservoir, and maximizing the use of existing facilities. 5 Wells will be drilled between existing IPA wells, eliminating 6 the need to expand the E-pad. A schematic of the drill site 7 layout is shown in Exhibit 111-2. This schematic shows 8 facilities for local source water injection system. As an 9 alternative, the Midnight Sun owners are working towards 10 approval to use GC1 produced water as a water source for the 11 Midnight Sun project. 12 No new pipelines will be required for development of ( 13 the Midnight Sun reservoir. Midnight Sun production will be 14 routed to GC1 via existing E-pad high pressure and low pressure 15 commonlines. No new roads or roadwork will be required. 16 Drill Site Facilities and Operations. Two existing E- 17 pad production manifold slots and well lines will be used for 18 the Midnight Sun wells. Water for the waterflood operations 19 will be obtained from either source water wells drilled at E- 20 pad or produced water delivered by pipeline from GC1. If the 21 source water system is installed, the source wells would be 22 equipped with electrical submersible pumps to deliver water to 23 the project. The source water injection system option is 24 illustrated in Exhibit 111-3. 25 Future gas lift gas will be obtained from an 1PA E-pad ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( ~ 37 f 1 well. Gas removed from this well for raw gas lift will be 2 metered prior to the gas being introduced into the Midnight Sun 3 well. This IPA gas will be returned to the IPA. 4 If initial power is needed beyond currently available 5 capacity at E-pad, it will be provided by installing a new 15 6 kv power line from GC1 to the Midnight Sun facilities at E-pad. 7 All well control at the drill sites will be performed manually 8 by a drill site operator, with the exception of well safety 9 shut in system, which are automatic, and the drill site 10 emergency shutdown system, which can be triggered manually or 11 automatically. 12 Initially, production will be allocated based upon well 13 tests as previously approved by the Commission. After a new ( 14 metering skid is installed in the third or fourth quarter 2000, 15 Midnight Sun production will be continuously metered prior to 16 combing with IPA production. The skid will consist of a two 17 phase separator, with liquids measured by a mass meter and gas 18 production measured by conventional orifice plate methods. The 19 Midnight Sun oil gravity will be used to calculate the oil and 20 water volumes based on liquid mass measurement. After 21 metering, the gas and liquid streams will be re-combined and 22 commingled with IPA fluids at E-pad for transport to GC1. The 23 data obtained from the metering skid will provide the basis for 24 allocating production between Midnight Sun and the IPA. 25 Production allocation is addressed later in Section V. ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ~. ", ~ 38 ( 1 Data gathering at the drill site will be both 2 manual and automatic. The data gathering system, SCADA, will 3 be expanded to accommodate the Midnight Sun wells and drill 4 site equipment. The SCADA will continuously monitor the 5 flowing status, pressures, and temperature of the producing 6 wells at the drill sites. These data will be under the drill 7 site operator's supervision through his monitoring station. 8 Midnight Sun production metering will continuously monitor the 9 pressures, temperatures, and flow of the liquid and gas 10 streams. 11 The rate of production from each well will be regulated 12 by manually adjusted chokes. The flow from the wells would be 13 routed to the production metering skid and then to GC1 for ( 14 processing. 15 Production Center. No modifications to the GC1 16 production center will be required to process the Midnight Sun 17 production. GC1 was built to process a nominal oil rate of 18 400,000 barrels of oil per day, gas rate of 320 million 19 standard cubic feet per day. Modifications have increased this 20 to 2,600 million standard cubic feet per day and a produced 21 water rate of 4,000 -- 40,000 barrels of water per day. 22 Modifications have increased this to 85,000 barrels of water 23 per day. Production, including that from the Midnight Sun 24 reservoir, is not expected to exceed GC1 capacity. This 25 concludes my testimony on facilities for the Midnight Sun Oil ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. calls for drilling one additional upstructure well to complete 24 schematic of the E-I00 well. The Midnight Sun depletion plan 23 to convert E-I00 to injection service. Exhibit IV-1 shows the 22 Pool, E-I00 and E-I01. E-I01 is currently producing with plans 21 Well Design. Two wells have been drilled in the Midnight Sun MR. REINBOLD: Well Operations. Drilling and Okay. Thank you. COMMISSIONER SEAMOUNT: COMMISSIONER OECHSLI TAYLOR: I don't think so. that we need to go through that again, do we? considered Mr. Reinbold as an expert witness. I don't believe COMMISSIONER SEAMOUNT: We've already will be presented by Eric Reinbold. MR. ECK: The next section, Well Operations, COMMISSIONER SEAMOUNT: Thank you, Mr. Eck. COMMISSIONER OECHSLI TAYLOR: I don't. questions, Commissioner Oechsli? Do you have any COMMISSIONER SEAMOUNT: MR. ECK: Yes. COMMISSIONER SEAMOUNT: One of the larger ones? sites so it's quite large. how much gravel is there. It is one of the original drill MR. ECK: I don't know off the top of my head area covered by pad E, do you know? COMMISSIONER SEAMOUNT: Thank you. What's the 1 Pool. 39 If , ( 25 20 19 2 3 4 5 6 7 8 9 10 11 12 13 ( 14 15 16 17 18 ( 40 <' 1 the initial development plan. If the source water injection 2 system is installed, two shallow source wells would also be 3 drilled. 4 Midnight Sun wells would be directionally drilled from 5 E-pad utilizing drilling procedures, well designs, and casing 6 and cementing programs similar to those currently used in other 7 North Slope fields. A 20 inch conductor casing will be set 80 8 feet below pad level and cemented to surface. Consideration 9 will be given to driving or jetting the 20 inch conductor as an 10 alternative setting method. A diverter system meeting 11 Commission requirements will be installed on the conductor. 12 Surface hole would be drilled no deeper than 5/000 feet 13 tvd subsea. This setting depth provides sufficient kick ( 14 tolerance to drill the wells safely and allows the angle-build 15 portions of high departure wells to be cased. No hydrocarbons 16 have been encountered to this depth in previous Midnight Sun 17 wells. Cementing and casing requirements similar to other 18 North Slope fields will be adopted for Midnight Sun. 19 The casing head in a 5/000 psi blowout-preventer stack 20 will be installed onto the surface casing and tested consistent 21 with Commission requirements. Production hole will be drilled 22 below the surface casing to the Kuparuk Formation allowing 23 sufficient rathole to facilitate logging. production casing 24 will be set and cemented. Intermediate casings and production 25 liners will be used to achieve specific completion objectives ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 (i- (' 18 19 20 21 22 23 24 25 ~, {, 41 1 or to provide sufficient contingency in mechanically 2 challenging wills such as high departure wells. 3 To date, H2S has not been detected in any Midnight Sun 4 wells. However, with planned waterflood operations, there is 5 some potential of generating small amounts of H2S over the life 6 of the field. 7 Safe drilling practices to account for the effects of 8 the H2S gas on both people and equipment will be followed, 9 including continuous monitoring for the presence of H2S. A 10 readily available supply of H2S scavenger, such as zinc 11 carbonate, will be maintained to treat the entire mud system. 12 Emergency operating and remedial protective equipment will be 13 kept at the wellsite. All personnel on the rig will be 14 informed of the dangers of H2S, and all rig site supervisors 15 will be trained for operations in an H2S environment. 16 The nature of the wells to be drilled requires the use 17 of E-75, G-I05, or S-135 grade drill pipe. These materials are susceptible to sulfide stress cracking but can be used safely under controlled conditions recommended in Section 8, Drill Stem Corrosion and Sulfide Stress Cracking, of API RP 7G, Drill Stem Design and Operating Limits, which will be used as applicable. Well Design and Completions. Contingent water supply wells would be drilled into the Tertiary interval and completed with a single casing string and downhole electric submersible MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( it 42 ( 1 pumps. Open hole gravel packs would be used in the water 2 supply wells to maximize productivity and present -- prevent 3 sand production. 4 The upstructure horizontal producer is planned with a 5 measured depth of over 14,000 feet, and would be completed in 6 the Kuparuk Formation. This departure would necessitate top- 7 setting the Kuparuk. In general, the production casing will be 8 sized to accommodate the desired tubing size in the Midnight 9 Sun wells. The following table indicates the casing and tubing 10 sizes utilized in the proposed well designs for the Midnight 11 Sun wells. Tubing sizes vary from 3-1/2 to 4-1/2 inches in the 12 Midnight Sun wells. And the table is shown in the text. It's 13 not an exhibit. { '\. 14 Plans are to run L-80 tubing and casing in these wells. 15 All tubing jewelry will be completed with 9-Chrome/lMoly, which 16 is compatible with both L-80 and 13-Chrome. 17 All proposed wells call for completion in a single zone 18 with a single string and a single packer. As shown in the 19 schematic, the wells have gas lift mandrels with dummy valves 20 to provide flexibility for artificial lift if needed to enhance 21 production rates. Sufficient mandrels will be run to provide 22 flexibility for changing well production volumes, gas lift 23 supply pressure, and changes in water-oil ratio. 24 Surface Safety Valves. Or excuse me, Subsurface Safety 25 Valves first. Subsurface safety valves do not appear to be ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 43 t ,( 1 necessary to Midnight Sun wells according to statewide 2 regulations 20 AAC 25.265. Existing completions are equipped 3 with subsurface safety valve nipples. The upstructure producer 4 would be completed in a similar manner. 5 Surface Safety Valves. Surface safety valves are 6 included in the wellhead equipment. These devices can be 7 actuated by high and low pressure sensing equipment, and are 8 designed to isolate produced fluids upstream of the surface 9 safety valve if pressure limits are exceeded. Testing of 10 surface safety valves will be in accordance with the standard 11 Prudhoe Bay Unit operator practices. 12 Drilling Fluids. In order to minimize skin damage from 13 drilling and to maintain shale stability, water-based KCl mud ( 14 will be used to drill through the Midnight Sun Pool and nearby 15 shales will be low solids, non-dispersed fluids excuse me, 16 while non-dispersed fluids will be used in the upper sections 17 of the well. 18 Stimulation Methods. Stimulation to enhance 19 productivity or injectivity capability is not currently planned 20 for Midnight Sun wells. Formation damage associated with 21 drilling and completion activity appears to be minor or 22 insignificant. The use of stimulation in the medium to high 23 permeability rock may be evaluated at a later date. 24 Reservoir Surveillance Program. The Midnight Sun data 25 will continue to be collected to monitor reservoir performance ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 (: 10 11 12 13 ( 14 15 16 17 18 19 ( 44 1 and define fluid properties. 2 Reservoir Pressure Measurements. An initial static 3 reservoir pressure will be measured in each well prior to 4 production. Additionally, a minimum of one pressure survey 5 will be taken annual for the Midnight Sun Pool. This will 6 consist of stabilized static pressure measurements at bottom 7 hole or may be extrapolated from the surface, pressure fall- 8 off, pressure build-up, multi-rate tests, drill stem tests, and 9 open-hole formation tests. The reservoir pressure will be reported at the common datum elevation of 8,050 tvd subsea. Surveillance Logs. Surveillance logs, which may include flow meters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance, for example, gas-oil contact monitoring and injection profile evaluation. That concludes my testimony on well operations for the Midnight Sun Pool. And if there are any questions, I can address those. COMMISSIONER SEAMOUNT: You stated that 20 subsurface safety valves are not necessarily indicated by 21 regulations. Does that mean that you don't plan to use the 22 subsurface safety valve? 23 MR. DAGGETT: Yeah. Currently we do not have 24 safety valves installed. There are nipples, profiles where we 25 could install them if necessary but currently they're not. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. ownerships within the PA, and with eventual approval by the 25 (indiscernible) agreement that's recently been signed, the 24 MR. GROTH: However, with the Prudhoe Bay Unit 23 22 and Exxon Mobile and Phillips share the remainder. 21 2.75 percent owned by BP, or the tract participations are such, 20 of the participating area. Inside the participating area, it's 19 Formation, the ownership would be the lease ownerships outside MR. REINBOLD: Within the Kuparuk River 18 17 difference in ownership as you come out of the PA? 16 of the PA? Actually, what I'd like to know is there a What is the ownership COMMISSIONER SEAMOUNT: 15 MR. REINBOLD: Okay. 14 (' 13 area. Can anyone address that? 12 I would like to learn something about the ownership of the 11 Reinbold, but would you put the -- one of those maps back up. 10 the one that would want to answer this next question, Mr. COMMISSIONER SEAMOUNT: I'm not sure if you're 9 8 four percent. MR. REINBOLD: Somewhere -- it's in two and 7 6 (indiscernible). UNIDENTIFIED SPEAKER: It's less than 5 MR. REINBOLD: It's two to four. 4 3 that out yet? 2 KCl you're going to be using for drilling? Have you worked COMMISSIONER SEAMOUNT: What is the percentage 1 (' 45 .¡:' 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. combination of well tests and wellhead pressure trends will 25 Section V. Production Allocation. Initially, a 24 23 production allocation activities for Midnight Sun. 22 concept of continuous metering allocations, and the details of 21 will discuss the incentives for commingled production, the MR. ECK: In this portion of the testimony, I 20 19 been recognized as an expert witness. Please proceed. 18 COMMISSIONER SEAMOUNT: Mr. Eck has already 17 production allocation. Dan Eck will be presenting that. MR. REINBOLD: The next section is on I'm sorry. COMMISSIONER SEAMOUNT: 12 13 ( 14 15 actually. 16 MR. GROTH: We have several more sections MR. GROTH: We have... . . I'm sorry. COMMISSIONER SEAMOUNT: 11 MR. GROTH: No. 10 9 applicants finished? 8 present testimony? I haven't seen any questions. Are the 4 in all of these leases that are associated with this PA would 5 be at the (indiscernible) . 6 COMMISSIONER SEAMOUNT: Okay. Thank you. 7 Where's the sign in sheet? Did anyone else say they wanted to 3 Phillips Alaska, BP Amoco, and Exxon Mobile. And so ownership 2 these leases in this area are held by the three parties, 1 State of a cross assignment of the leases, and I believe all of ( 46 ( ~. :f 47 ( 1 continue to be used to allocate production. Under this 2 methodology, the production from an individual well is first 3 calculated from the average daily wellhead pressure using the 4 deliverability equation. During periods of rising GOR and 5 changing tubing hydraulics, the deliverability equation may not 6 accurately reflect the production as measured by well tests. 7 During such periods, the daily well production is determined by 8 linear interpolation between well test points. A minimum of 9 two well tests per month, as well as lab-measured water cuts 10 and zero-rate tests, are performed on Midnight Sun wells to 11 ensure allocation accuracy. Summing the calculated data 12 calculated daily production volume for all producing wells 13 provides an estimate of the Midnight Sun daily field ( 14 production. A fixed allocation factor of 1.0 is used for the 15 Midnight Sun. 16 The long-term metering plan for Midnight Sun is to use 17 continuous production metering. The metering skid described in 18 the facility section of this application will be used to 19 continuously meter the entire Midnight Sun production stream 20 through a compact two-phase separator before it is commingled 21 with the IPA production at E-pad. Each wellhead will have a 22 continuous two phase meter to monitor fluid and gas production 23 with monthly shakeouts to ascertain water cut. We request 24 Commission approval under 20 AAC 25.215(a) that the Midnight 25 Sun metering is an acceptable method. An allocation factor of ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. previously been shown, shows the location all existing 25 Plat of the Project Area. Exhibit 1-2, which has 24 23 requirements of 20 AAC 25.402(c). 22 Midnight Sun Oil Pool. This section addresses the specific 21 authorization for water injection to enhance recovery for the 20 and 20 AAC 25.460, Area Injection Orders, requests 19 accordance with 20 AAC 25.402, Enhanced Recovery Operations¡ 18 area injection operations. This application, prepared in MR. REINBOLD: Thank you. Section VI is the 17 16 Reinbold. Please proceed, Mr. COMMISSIONER SEAMOUNT: 15 14 operations, will be presented by Eric Reinbold. ( \ MR. ECK: The next section, area injection 13 Thank you, Mr. Eck. COMMISSIONER SEAMOUNT: 12 11 any questions. Thanks. COMMISSIONER OECHSLI TAYLOR: No, I don't have 10 COMMISSIONER SEAMOUNT: Questions? 9 8 for the Midnight Sun Oil Pool. 7 This concludes the testimony on production allocation 6 NGLs will be allocated to Midnight Sun. 5 allocation factors. Consistent with existing reporting, no 4 continuous two-phase metering data to calculate wellhead 3 production allocated back to individual wells using the 2 Midnight Sun Pool will have a set allocation factor of 1.0 with 1 1.0 would continue to be used with the continuous meter. The ( 48 ~' ;f 49 (" 1 injection wells, production wells, abandoned wells, dry holes, 2 and any other wells within the Midnight Sun Pool as of April I, 3 2000. Specific approvals for any new injection wells or 4 existing wells to be converted to injection service will be 5 obtained pursuant to 20 AAC 25.005, 25.280, and 25.507, or any 6 applicable successor regulation. 7 Operator and Surface Owners. Phillips Alaska, Inc., is 8 the designated operator of the Midnight Sun Participating Area. 9 Surface owners within a one-quarter mile radius and inclusive 10 of the Midnight Sun Participating Area are as follows: and 11 listed here is only the State of Alaska Department of Natural 12 Resources, Ken Boyd P.O. Box 107034, Anchorage, Alaska 99510. 13 Pursuant to 20 AAC 25.402(c) (3), Exhibit VI-l shown here is an ( 14 affidavit showing that the operators and surface owners within 15 a one-quarter mile radius of the area and inclusive -- and 16 including -- included within the Midnight Sun Participating 17 Area have been provided a copy of this application for 18 injection. 19 Description of Operation. Development plans for the 20 Midnight Sun Pool are described in Section II of this 21 application. Drill site facilities and operations are 22 described in Section III. If the source water injection system 23 is installed, source water wells will be permitted and 24 construction -- and constructed in accordance with 20 AAC 25 25.005. ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 50 ( 1 Geological Information. The geology of the Midnight 2 Sun Pool has been described in Section I of this application. 3 Injection Well Casing Information. The E-100 well will 4 be converted to injection service for the Midnight Sun Oil Pool 5 Enhanced Recovery Project. The casing program for this well 6 was permitted and completed in accordance with 20 AAC 25.030. 7 Exhibit IV-1 already shown details the completion for the E-100 8 well. A cement bond log was recorded and indicated good cement 9 bond across and above the Kuparuk River Formation. Conversion 10 of the E-100 well will be conducted in accordance with 11 20 AAC 25.412. 12 The actual casing program is included with the 13 application to drill for each well. It is documented with the ( 14 AOGCC in the completion record. API injection casing 15 specifications are included on each drilling permit 16 application. All injection casing is cemented and tested in 17 accordance with 20 AAC 25.412 for both newly drilled and 18 converted injection wells. All drilling and production 19 operations will follow approved operating practices regarding 20 the presence of H2S in accordance with 20 AAC 25.065. 21 Injection Fluids. Type and - - Type of Fluid and 22 Source. The Midnight Sun Enhanced Recovery Project will 23 utilize either GC1 produced water or water produced from the 24 Tertiary Sagavanirktok Formation, as shown in Exhibit VI-2, as 25 an initial and primary source. So this is Exhibit VI-2 and it ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 :t t 51 f 1 just shows the interval that we would acquire water from if we 2 installed the source well system. 3 COMMISSIONER SEAMOUNT: What kind of rates do 4 you anticipate? 5 MR. REINBOLD: What kind of rates? 6 COMMISSIONER SEAMOUNT: Uh-hum. 7 MR. REINBOLD: The design rate is 10,000 8 barrels a day for each source well. 9 COMMISSIONER SEAMOUNT: Okay. 10 MR. REINBOLD: Composition. First, Tertiary 11 Water. The water sample from the Tertiary -- or a water sample 12 from the Tertiary water source interval has not been obtained. ,( 13 However, it's anticipated the water will be of similar 14 composition as water produced from the drill site 15-6 well in 15 the Cretaceous interval. The drill site 15-6 water composition 16 is shown in Exhibit VI-3. 17 GC1 Produced Water. The composition of produced water 18 from GC1 is shown in the next exhibit, Exhibit VI-4. The 19 composition of Midnight Sun produced water will be a mixture of 20 connate water and source injection water. No water-oil contact 21 has been identified in the Midnight Sun Pool, and no 22 significant connate water production has occurred or is 23 anticipated. In order to conduct geochemical modeling, the 24 Midnight Sun Oil Pool connate water composition is assumed to 25 be similar from samples from the offset Point McIntyre Oil ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 52 ( ( 1 Pool. Refer to Exhibit J-3 in the application for modification 2 to area injection order number 4, dated April 5, 1993. 3 Maximum Injection Rate. Maximum water injection rates 4 required at the Midnight Sun Pool are estimated at 25,000 5 barrels of water a day. 6 Compatibility with Formation and Confining Zones. Core 7 analyses and geochemical modeling indicate no significant 8 problem with clay swelling or compatibility with in-situ 9 fluids. Analysis of the E-101 core indicates a low clay 10 content, less than five percent by volume, primarily in the 11 form of kaolinite and illite. No fines migration problems are 12 anticipated. 13 Geochemical modeling results indicate that a ( 14 combination of Tertiary water and connate water is likely to 15 form calcium carbonate and barium sulfate scale in the 16 production wells and downstream production equipment. Similar 17 scaling problems are anticipated for GC1 produced water and 18 connate water. Scale precipitation will be controlled using 19 standard oil field scale inhibition methods. 20 Injection Pressures. The expected average surface 21 water injection pressure for the project is 2,250 psig. The 22 estimated maximum surface injection pressure for the Midnight 23 Sun Pool Enhanced Oil Recovery Project is 2,750 psig. The 24 resulting bottom hole pressure will be limited by hydraulic 25 pressure losses in the well tubing, with a maximum expected ( " MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. The Kuparuk River Formation at the Midnight Sun Oil 25 exceed the integrity of the confining zone. 24 confirm that injection above the parting pressure will not 23 22 and improve recovery of oil. Fracture propagation models 21 Kuparuk River Formation parting pressure to enhance injectivity 20 Midnight Sun Oil Pool are expected to be above the formation -- Enhanced Recovery. Water injection operations at the 19 18 would not come in contact with freshwater strata. 17 through all confining strata, injection or formation fluid 16 Formation. Therefore, even if a fracture were propagated 15 the Cretaceous and Tertiary sands above the Kuparuk River 14 indicate a salinity range of 40 to 45,000 parts per million for ( 13 hole resistivity logs acquired in the Prudhoe Bay well E-16 12 5, 1993. Additionally, calculations of water salinity for open 11 Modification to the area injection order number 4, dated April 10 the area of issue. See Section N of the application for Freshwater Strata. There are no freshwater strata in 9 8 Formation waterflood operations in the North Slope. 7 evidence of injection out of zone for similar Kuparuk River 6 formation fluid to enter any freshwater strata. There is no 5 the confining strata, and therefore will not allow injection or 4 Project wells will not initiate or propagate fractures through 3 pressure for the Midnight Sun Oil Pool Enhanced Recovery Fracture Information. The expected maximum injection 2 1 bottom hole pressure of 6,000 psig. ( 53 it (- 11 12 13 ( 14 15 16 17 18 ( { 54 1 Pool is overlain by the Kalubik and HRZ shales, which have a 2 combined thickness of approximately 110 feet. The HRZ is a 3 thick shale sequence which tends to behave as a plastic medium, 4 and can be expected to contain significantly higher pressures 5 than sandstones of the Kuparuk River Formation. Mechanical 6 properties determined from log data for the HRZ and Kalubik 7 intervals indicate a fracture gradient from approximately 0.8 8 to 0.9 psi per foot. 9 No tests have been conducted to determine the formation 10 breakdown pressure at the Midnight Sun Oil pool. However, data from offset fields suggest that a fracture gradient of between 0.6 and 0.7 psi per foot can be expected in the Kuparuk River Formation at initial reservoir conditions. The Kuparuk River Formation is underlain by the Miluveach and Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrates leakoff at a gradient of approximately 0.85 psi per foot. In addition, rock mechanics calculations and data from 19 the Prudhoe Bay Oil Pool indicate that sandstone fracture 20 gradients are reduced during waterflooding operations due to 21 reduced in-situ rock stress associated with the injection of 22 water that's colder than the reservoir. A tertiary water 23 source system would have an expected surface water injection 24 temperature of 60 to 80 degrees Fahrenheit, resulting in a 25 fracture gradient reduction of 0.3 to O. -- I'm sorry, excuse MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. that, it should be arriving shortly. 25 24 conversion of that well to injection. So, if you haven't seen 23 operation in the Sag River Formation in that well prior to the 22 submitted a request of the Commission to approve a testing 21 Ivishak. With regard to the Sag River though, we just MR. GROTH: We spoke with future plans on the 20 COMMISSIONER SEAMOUNT: Okay. 19 18 regarding plans for the deeper horizons and the E-I00 well. 17 opportunity to elaborate on one question that was asked earlier MR. GROTH: If I may, we appreciate the 16 15 any written questions. Mr. Groth. COMMISSIONER SEAMOUNT: Well, I haven't seen 14 ( 13 questions, we can address those now. 12 testimony for the combined application. So, if there are any 11 operations for the Midnight Sun Pool. It also concludes our 10 This concludes the testimony on the area injection 9 depletion. 8 percent of the original oil in place relative to primary 7 incremental recovery from waterflood to be between 15 to 25 6 stock tank barrels. Reservoir stimulation studies indicate 5 estimated to have an original oil in place of 40 to 60 million Hydrocarbon Recovery. The Midnight Sun Oil Pool is 4 3 water temperature would be close to the reservoir temperature. 2 would have limited impact on the fracture gradient because the 1 me, 0.03 to 0.05 psi per foot. The produced water from GCl i( 55 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ( MET ROC 0 U R T R E P 0 R TIN G, INC. 25 24 23 22 21 20 19 18 17 16 15 END OF PROCEEDINGS 14 f \ (Off record 10:52 a.m.) 13 12 it's appropriate to go ahead and close the meeting. Thank you. 11 good project. We wish you all the best of luck. And I guess 10 You've given a very complete presentation. Looks like a very 9 questions, we would like to thank the applicant for coming in. Yes. If there are no COMMISSIONER SEAMOUNT: 8 7 was an excellent presentation. COMMISSIONER OECHSLI TAYLOR: I don't. That 6 5 you have any questions, Commissioner Oechsli? Thank you. Well, do COMMISSIONER SEAMOUNT: 4 MR. GROTH: Thank you. 3 2 interesting. COMMISSIONER SEAMOUNT: Great. Sounds 1 (: 56 (¡ ~ it ( 1 C E R T I FIe ATE 2 UNITED STATES OF AMERICA) ) ss . 3 STATE OF ALASKA ) 4 I, Laura Ferro, Notary Public in and for the State of 5 Alaska, and Reporter for Metro Court Reporting, Inc., do hereby 6 certify: 7 That the foregoing Alaska Oil & Gas Conservation 8 Commission Public Hearing, was taken before myself on the 21st 9 day of June 2000, commencing at the hour of 9:23 o'clock a.m., 10 at the offices of Alaska Oil & Gas Conservation Commission, 11 3001 Porcupine Street, Anchorage, Alaska; 12 That the hearing was transcribed by myself to the best 13 of my knowledge and ability. ( 14 IN WITNESS WHEREOF, I have hereto set my hand and 15 affixed my seal this 3rd day of July 2000. 16 ~-:;-~ 17 Notary Public in and for Alaska My commission expires: 05/03/01 18 19 20 21 22 23 24 25 ( MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 #11 ) " ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING JUNE 21, 2000 9: 15 AM MIDNIGHT SUN NAME - AFFILIATION TELEPHONE Do you plan to testify? Yes No (PLEASE PRINT) K V"C~ NeJ~,/f>J$ A- ---.¡~('~~, I t+ .- ~ (f:."L-<-I/'..(" riJ6J;l \ 'ìn~Qtt ':Ph((\(~ ~VL Fe: / ~~1:~> '-¡:;¿~ìt ß:¡/lb/LI MJ¿Í;s Mavl'- (¡(}(?~C,~ PÆ( ~A(¿L- L v",J~~t!',.J :::PAl rt~ ~s iòQ(~ \\0/.)\ \ ";::!A -JIC> ~\ (~{\J 0 P X Ihrt.u;~ S ,worJf¡ - ~M~bj I , S ~ H Û.~-Lkrt- ry ,. l~",<~o1. ~~( I ¡tllc~-ft.,n-- ~¡'¡rJ~o¡ù - fhxOrJ /108/1.- 7)o'fl' -letS /~~tJ 8. Px ./ ,,-- N r (LI¡¡( lóskt/CLS-'1 fM E¡¿IC PLETCI-IE12. Exxof! Mob; / bti Crt?~)~)/ ,¡I/ó!:r- ~ J; M '-!-OÙ^I(-, pAl ",5-/L ere- ~ct 1/ /~5 ¡/1(j(j:~C ;Zlf8'36~ ~ 2(,~~s~~ %S "f 504- ~c'S-- ~JOPJ /6~'-~~ .?eo ~ -& ç-I.,( l{ "2.. ~~-. tø'2..0 ~ Y'þJ' Yés y~~ f~' Soy· ~1l0 'R,þ $.(Lf -. )5ìb 6(04, '··11~ $~1-]?;;J ~ ç ~ ~.- 3"7 II c')l.; ý-5J52 2(.,5- 1'1~b 56Lj - 36ò 7 ?Y'?~/? 36 2C ~ -' '-I SO L/ /73-/22-1 rvo l/l (,1 rJo No {J,;; NO tJ'C:'. ,No No (Va ND M1 rvc) /\/~) #10 June 21, 2000 Revised Area Injection Application Midnight Sun Oil Pool Pool Rules And '{ ( \ ( ( Midnight Sun Pool Rules and Area Injection Application ¡" 1, June 20, 2000 { Table of Contents I. Geology p. 1 IT. Reservoir Description and Development Planning 5 ill. Facilities 15 N. Well Operations 18 V. Production Allocation 22 VI. Area Injection Operations 23 VIT. Pool Rules- Proposed Findings, Conclusions, and Rules 29 Vill. Area Injection Application - Proposed Findings, Conclusions, and Rules 37 IX. Exhibits 41 ( Midnight Sun Pool Rules and Area Injection Application ( June 20, 2000 I. Geology Introduction The Midnight Sun Pool is located on Alaska's North Slope, as illustrated in Exhibit I-I. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E-100) well. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. The E-100 well is the first well to encounter the Kuparuk River Formation in this area. The Fawn Lake #1, Abel State #1, North Prudhoe Bay State #1 and #2, North Prudhoe #3, Term Well A wells, and wells drilled from nearby pads in the Prudhoe Bay Field did not encounter the Kuparuk River Formation. Exhibit 1-2 shows the location of the Midnight Sun Participating Area (MSPA). Development drilling will utilize the existing gravel E-pad, from which the E-100 discovery well was drilled. One delineation well, the Midnight Sun #1 (E-101), was drilled from E-pad in October 1998 to confirm the extent of the Midnight Sun discovery. Stratigraphy The Midnight Sun Pool is composed of the Kuparuk River Formation, also informally referred to as the "Kuparuk Formation". This formation was deposited during the lower Cretaceous geologic time period, between 153 and 115 million years before present. Exhibit 1-3 shows a portion of the open hole electric logs from the E-100 well. This "type log" illustrates the stratigraphic definition of the Midnight Sun Pool. The log is scaled in true vertical depth subsea (tvdss) and also has a measured depth (md) track. In the E-100 well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 f1. md) and the base occurs at 8,074f1. tvdss (11,805 ft. md). This is also the productive interval of the Midnight Sun Pool. The Kuparuk Formation base is defined by its contact with the Jurassic-age Kingak Formation as Page 1 of 41 ( Midnight Sun Pool Rules and Area Injection Application ( June 20, 2000 seen with a change in lithology and conventional electric log character. The Kingak Formation is a shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation is composed of medium- to fine-grained quartz-rich to glauconitic sandstone with higher resistivity (3-50 ohm- meters). The Kuparuk Formation top is defined by its contact with the lower Cretaceous-age High Radioactive Zone (HRZ) Formation as seen by a change in lithology and conventional electric log character. The HRZ is a black, organic-rich shale recognized by the gamma ray log, typically greater than 150 gamma API units. The Kuparuk Formation in the Midnight Sun Pool is stratigraphically complex, characterized by rapid change in thickness, sedimentary facies and local diagenetic cementation. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. As shown on the type log in Exhibit 1-3, the Kuparuk Formation can be divided into upper and lower units. The basal portion of the lower unit in E-I0l is a non-productive, tight, glauconitic sandstone with minor amounts of shale rip-up clasts. This unit was not encountered in E-IOO and is assumed to be restricted to the area near E-I0 1. Moving up in the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fine to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. The sands in the upper unit are poorly to well- sorted. Intergranular siderite cement is common in the upper unit and plays an important role in determining reservoir quality. Cementation is especially abundant in the lower portion of the upper unit where it degrades reservoir quality. The upper and lower units have distinctly different thickness trends. The lower unit maintains a nearly uniform thickness throughout the Midnight Sun area, suggesting that its deposition predates significant fault movement. In contrast, the thickness and lithology of the upper unit are variable and have been influenced by syn-depositional faulting. Page 2 of 41 (' Midnight Sun Pool Rules and Area Injection Application ( June 20, 2000 Structure Exhibit 1-4 is a structure map on the top of the Kuparuk Formation with a contour interval of 20 feet. Top Kuparuk structure in the Midnight Sun area is characterized by a bowl-shaped depression gently dipping to the northeast. The Midnight Sun depression is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural highs surrounding the Midnight Sun accumulation are devoid of Kuparuk Formation rock. Along the axis of the depression, the structural dip is less than 2 degrees, down to the northeast. Exhibit 1-5 is an isochore map of the Kuparuk Fonnation with a contour interval of 10 feet. The Midnight Sun accumulation is a combination structural/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Fonnation thickness are fault movement and erosional truncation. Kuparuk Formation deposition occurred in marine shoreface and deltaic depositional environments. Exhibit 1-6 is a structural cross-section along the axis of the Midnight Sun structural depression (see Exhibit 1-1 for location). This cross-section illustrates the western and eastern limits of the Midnight Sun Pool. The western limit of the pool is fault-controlled by the Prudhoe Mid-Field fault and the eastern boundary is a stratigraphic truncation of the Kuparuk Formation onto the North Prudhoe structural high. Exhibit 1-7 is a north-south structural cross-section through the Midnight Sun Pool (see Exhibit 1-1 for location). This exhibit illustrates the fault-bounded isolation of the Kuparuk Formation on the north by the Sambuca fault and on the south by the Prudhoe bounding fault system. Fluid Contacts The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, Page 3 of 41 ( Midnight Sun Pool Rules and Area Injection Application ( June 20,2000 based on Repeat Formation Tester (RFf) data. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. Based on core water saturation data and Mercury Injection Capillary Pressure data, the reservoir is interpreted to be significantly above the effective OWC. Heavy oil was encountered at 8,107 ft. tvdss in the E-10 1 well. A heavy oil sample, measuring 10 degrees API gravity, was recovered by the RFf at 8,107 ft. tvdss. Conventional core from the E-I01 well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Pool Limits The trap for oil and gas in the Midnight Sun Pool is created by a combination of structural and stratigraphic features. To the south, west, and north, the pool limit is defined by the juxtaposition of the reservoir against the impermeable Kingak shale across the Prudhoe bounding fault system, Prudhoe Mid-Field fault, and Sambuca fault, respectively. Stratigraphic truncation of the Kuparuk Formation forms the trapping mechanism to the east. The boundaries of the Midnight Sun P A encompass the proposed boundaries of the Midnight Sun Pool. Exhibit 1-8 is a net sandstone map of the Midnight Sun Pool with a contour interval of 2-feet. Exhibit 1-9 is a gross hydrocarbon distribution map of the Midnight Sun Pool. Page 4 of 41 ( Midnight Sun Pool Rules and.h.rea Injection Application ~ June 20, 2000 II. Reservoir Description and Development Planning ROCK AND FLUID PROPERTIES The reservoir description for the Midnight Sun Pool is based on core data from the E-1 0 1 well and log data from the E-100 (Sambuca #1) and E-101 (Midnight Sun #1) wells. Well E-101 was cored through the entire Kuparuk section with water based mud and low invasion coring techniques. The core data were used to calibrate the petrophysical log model, which was used to construct the Midnight Sun geologic model. Porosity and Permeability Core porosity and permeability measurements were conducted at overburden pressure and permeability was corrected for gas slippage (Klinkenberg correction). Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. The ratio of vertical to horizontal permeability ranges from 0.2 to 1.0 in the upper Kuparuk Formation and from 0.6 to 1.0 in the lower Kuparuk Formation. Net Pay Net pay was determined based on visual inspection of the E-1 0 1 core in conjunction with review of thin section and routine core analysis data. The Kuparuk Formation in the Midnight Sun Pool has very low clay content, generally less than 2% by volume, and no defined shale sections. In the upper Kuparuk Formation, reservoir volume is reduced by the presence of discontinuous, nodular and banded siderite and glauconite. These mineral inclusions were identified visually, and the net-to-gross-ratio was determined based on the ratio of reservoir quality sand to gross rock area exposed on the slabbed core. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in Page 5 of 41 'i \ Midnight Sun Pool Rules and Area Injection Application l ~ June 20, 2000 the lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. Water Saturation Water saturation data were measured throughout the Kuparuk Formation interval in the E-l 0 1 low invasion core. A chemical tracer confirmed that the core experienced minimal invasion. Water saturation data were corrected for mud filtrate invasion based on the tracer results. Water saturation measurements from the core were then used to calibrate the petrophysical log model. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-I0l core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. Water saturation data derived from the core and log data were used to develop Leverett J- functions, which. were subsequently translated to drainage capillary pressure curves for the upper and lower Kuparuk Formation intervals. The capillary pressure data were then used to initialize water saturation in the reservoir model based on capillary pressure equilibrium. Relative Permeability A steady state water-oil relative permeability experiment was conducted on a composite core from the upper Kuparuk Formation interval. The residual oil saturation from this displacement experiment was 22.7%. Centrifuge water-oil and gas-oil experiments were also conducted. Results from these experiments indicate that water-oil relative permeability measurements for the Midnight Sun Pool are similar to those measured for other North Slope fields exhibiting favorable waterflood performance. In the absence of having an extensive data set for all relative permeability functions, analog data sets were used for performance predictions. Initial Pressure & Temperature Based on RFT data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit at the datum. Page 6 of 41 (' Midnight Sun Pool Rules and 1"~rea Injection Application ~( June 20, 2000 Fluid PVT Data Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-1 0 1 well. The sample was recombined to the bubble point pressure of 4045 psia, corresponding to the pressure at the GOC at initial conditions. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil-ratio (GOR) of 717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. Exhibit II-I shows a summary of the fluid property information for the Midnight Sun Pool. Exhibit II-2 contains a listing of the varIous pressure-volume-temperature (PVT) properties as a function of pressure. Hydrocarbons in Place Estimates of hydrocarbons in place for the Midnight Sun Pool reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. These data were integrated in the construction of a fine scale geologic model, which provides the basis for estimation of original fluids in place. The results indicate an Original Oil In Place (OOIP) range of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. RESERVOIR PERFORMANCE Well Performance Two wells (E-100, and E-1 0 1) have been drilled and completed in the Kuparuk formation. Both wells are tied into the Prudhoe Bay E-Pad facilities. Production commenced in October of 1998. Well E-100 (Sambuca #1), the discovery well, encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. The well was perforated over a 20 feet interval at the base of the reservoir. The initial production rate was 2,000 to 3,000 BOPD with a GOR of approximately 950 scf/stb. The rate was restricted to mitigate coning, although the GOR increased steadily to 6000 scf/stb during the first three months of production. The well is currently shut in to limit reservoir voidage. Page 7 of 41 \ Midnight Sun Pool Rules and Area Injection Application { ~ June 20, 2000 Well E-1.01 (Midnight Sun #1) was drilled as a downstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-I00 well. No oil-water contact was identified by open-hole logs. The initial production rate in November of 1998 was 7000 to 8000 BOPD with a GOR of approximately 800 scf/stb. In January of 1999, the well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. Gas Coning Production from the E-I00 well is affected by gas coning. E-I00 is a deviated well with an inclination of 46 degrees across the Kuparuk. The well is completed with a standoff of 42 feet tvd from the GOC. During the first 10 days of production, the GOR in the E-I00 well increased to 2000 scf/stb. The production rate was restricted to mitigate coning. The cement bond log in this well is interpreted to show good cement quality; and the coning interpretation was confinned by production logging. Subsequent inspection of the E-I0 1 core confirmed that intra-formation cementation in the upper Kuparuk would act as a baffle but not a barrier to vertical flow. With slightly more than 50% of the oil column overlain by the gas cap, coning can be a significant reservoir mechanism in the Midnight Sun Pool. Gas Under-Running The Midnight Sun reservoir is a thin reservoir with a structural dip of less than 2 degrees. The low structural relief results in a gas cap that overlays more than 50% of the areal extent of the oil column. Reservoir model results, calibrated to field performance, suggest that gas under-running, which is movement of gas below a barrier, will impact early field performance and is a mechanism to address in depletion planning. The GOR at well E-I0 1 is currently 5000 scf/stb and increasing consistent with predictions. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. Page 8 of 41 Midnight Sun Pool Rules anJ.c~lea Injection Application ( June 20, 2000 DEVELOPMENT PLANS A reservoir model of the Midnight Sun Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles for facility design. This section of the application describes the reservoir model, modeling results and the development plans. Reservoir Model Construction A fine scale three-dimensional geologic model of the Midnight Sun Pool was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk reservoir volume and distribution of porosity and permeability used in the construction of the Midnight Sun reservoir model. The reservoir model is a three-dimensional, three-phase, black oil finite difference flow simulation model. The model area encompasses the graben fault block· defining the Midnight Sun Pool. Areal gridding is 250 feet by 250 feet (1.43 acre cells). The vertical gridding is defined by 15 model layers with nominal thicknesses of 4 to 8 feet. Exhibit II-3 shows average physical properties for each model layer. Faults and juxtaposition are honored through comer point geometry and non-local grid connections. Water saturation in the reservoir model was established by capillary pressure equilibrium. There is no aquifer in the reservoir model. Capillary pressure measurements suggest that the effective owe is below the structural limit of the reservoir. The reservoir pressure was set to 4045 psia at the GOe of 8010 ft. tvdss, based on the RFT data. Exhibit ll-4 shows the comparison of model predictions and field performance. For the history match, oil rate is specified and reservoir pressure and well GOR are predicted. A history match of reservoir pressure was achieved with no modification to the gas cap volume in the reservoir model. The GOR history match reflects accurate modeling of both the coning (E-I00) and under-running (E-I0l) reservoir mechanisms. The downstructure pore volume was increased to reflect under-run timing at well E-l 0 1. Page 9 of 41 ( Midnight Sun Pool Rules and Area Injection Application \ June 20,2000 Model Results Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) upstructure gas injection, and 3) waterflood. Primary Recovery Primary recovery was evaluated with E-1 0 1 well as the single down structure producer. The primary recovery mechanism was a combination of gas cap expansion and solution gas drive. The gas cap at Midnight Sun contains approximately 40 percent of the total reservoir hydrocarbon pore volume. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP. Exhibit ll-5 shows production and recovery profiles for primary depletion. The performance is attributed to depletion of the gas cap and associated reduction in reservoir energy. The model shows gas under-running and high GOR production at Well E-101. The reservoir pressure was depleted at the end of the model run and the majority of the original gas cap volume had been produced. Upstructure Gas Injection Up structure gas injection was evaluated with a horizontal injection well installed in the Midnight Sun gas cap. Reservoir management for this case assumed that injection would be sufficient to increase reservoir pressure back to the original condition and then maintain a voidage replacement ratio (VRR) of 1.0. The peak injection requirement for this case was 40 MMscfd. Model results indicate that upstructure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI). Recovery of 27% was observed with 2.0 HCPVI. Exhibit ll-6 shows production and recovery profiles for upstructure gas injection. Upstructure gas injection results in gas under-running the top Kuparuk Formation and then coning into the perforations at the down structure producer. As a result of these mechanisms, the vertical sweep efficiency for up structure gas injection is poor with correspondingly low recovery in the lower Kuparuk Formation. Waterflood Several waterflood development options were studied using the Midnight Sun reservoir model including upstructure, downstructure, and midfield water injection. Both the Page 10 of 41 l' ~ Midnight Sun Pool Rules and Area Injection Application II 'I {, June 20,2000 upstructure and midfield options involve water injection at or near the original gas cap. All waterflood options result in some degree of resaturation of the gas cap by oil in the midfield area. Case studies of successful application of this type of waterflood process are documented in the literature. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-I00 well to injection service. Initial production was from the E-l 0 1 well. An up structure horizontal production well is completed 2,000 to 4,000 feet east of the western limit of the light oil column. This well was managed in the reservoir model to limit gas coning. The midfield waterflood shows improved waterflood response over the up structure and down structure injection options, as evidenced by lower peak GOR and faster pressure response. Waterflood fill-up is achieved within two years of waterflood start-up. The improved response is attributed to closer injector / producer spacing and greater distance of the key production well from the gas cap. The midfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. Cumulative gas production is lower relative to the up structure injection case. Exhibit II-8 shows production and recovery profiles for midfield water injection. The upstructure configuration included a new horizontal injection well towards the western limit of the light oil column. The configuration was envisioned as a means of isolating the gas cap while waterflooding the midfield and down structure areas. The primary downstructure producer would be well E-l 0 1, although the E-I00 well was also produced for a limited time. Model results for up structure water injection indicate that the western limit of the gas cap can be isolated, and classic waterflood fill-up and response are achieved within three years of waterflood start-up. The upstructure water injection case achieves an estimated 39% recovery at 0.7 HCPVI, although production response to waterflood is slower and gas production is greater relative to the midfield case. The down structure configuration involves converSIon of Well E-l 0 1 to injection servIce. Production from Well E-I00 would be resumed and rate would initially be restricted to mitigate Page 11 of 41 t Midnight Sun Pool Rules and Area Injection Application June 20, 2000 coning. In the downstructure waterflood configuration, an upstructure horizontal production well is drilled to recover up structure reserves. Waterflood performance for down structure injection is less attractive than the other waterflood configurations. In this configuration, gas coning and under-running at Well E-100 require restricted field rate and continue to be a production issue for both production wells. The down structure water injection case achieves an estimated 31 % recovery at 0.56 HCPVI with a delayed production profile relative to the upstructure and midfield alternatives. Enhanced Oil Recovery (EOR) Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated. Due to the technical complexities, reservoir uncertainty, and costs involved, improved reservoir description and additional field performance data are necessary before these options may be fully evaluated. Development Plans Based on reservoir model studies, the recommended development plan is implementation of a midfield waterflood for the Midnight Sun Pool. This plan provides the most favorable production profile, while minimizing cumulative gas production and maximizing ultimate recovery. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. Waterflood Sensitivity Studies Reservoir model sensitivity studies were conducted in support of development planning. Model runs were conducted to optimize well placement and completion design. Sensitivities to key model assumptions, including relative permeability, vertical permeability, and oil viscosity were evaluated. None of these assumptions were found to significantly alter development plans. Other sensitivity studies included the effect of continued production prior to waterflood startup. Earlier waterflood startup mitigates reservoir pressure decline and reduces peak GOR response prior to waterflood fill-up. However, no recovery impact was identified with a waterflood start- up during third quarter 2000, assuming continued production of 5,000 BOPD until start up. In Page 12 of 41 l Midnight Sun Pool Rules anl.. _d Injection Application ( June 20, 2000 the reservoir model, reservoir pressure declined to 3300 psi, and GOR peaked at 8000 SCF/STB. Well Spacing The planned development well program includes the addition of one upstructure horizontal production well to complete a three well development of the Midnight Sun Pool. The development will form an irregular pattern due to the constraints of development within a small fault block. This well spacing is nominally 280 acres. Closer well spacing does not appear to be justified due to the thin oil column; however, infill drilling and/or peripheral drilling along the eastern margin of the field will be evaluated as field development continues. To allow for flexibility to respond to these conditions, a minimum well spacing of 80 acres is requested. RESERVOIR MANAGEMENT STRATEGY Gas cap expansion will provide initial pressure support prior to waterflood start-up. Following waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. In the planned waterflood configuration, oil flux into the gas cap is anticipated in the midfield area due to low structural relief. Reservoir surveillance and voidage management, however, should minimize oil flux to the west of the upstructure horizontal producer. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to 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 historical performance. New well results and additional reservoir performance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Midnight Sun Pool will continue to be evaluated throughout field life. Page 13 of 41 / ! ~ Midnight Sun Pool Rules and" Area Injection Application l Ii \ June 20, 2000 Reservoir Performance Conclusions Reservoir model results support implementation of a waterflood in the Midnight Sun Pool. An initial three well development program is contemplated, with midfield water injection at Well E- 100, and the addition of one up structure horizontal producer. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. Following initiation of waterflood, a peak production rate of 8-10,000 BOPD is expected. We request that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. Page 14 of 41 / Midnight Sun Pool Rules and\¡-~lt:a Injection Application i ~ l June 201 2000 III. Facilities GENERAL OVERVIEW Midnight Sun wells will be drilled from the E-Pad drill site. Surface facilities include an existing IP A drill site, pipelines and processing facilities to produce Midnight Sun Reservoir fluids. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E-Pad and then transported to Gathering Center 1 (GC1) for treatment and shipment to Pump Station No.1 (PS-1). Midnight Sun will make use of existing IPA infrastructure. This minimizes environmental impacts and reduces costs to help maximize recovery. Use of the GC1 production facility includes separating and processing equipment, inlet manifold and related piping, flare system, and water injection facilities. IP A field facilities that will be used include 24" low-pressure common line from E-pad to GC1, 16" and 6" high-pressure common lines from E-pad to GC 1, oil sales line from GC 1 to PS-1 and the power distribution and generation facilities. Plans to deliver GC1 produced water to E-pad using an existing 6" IPA flowline are also being considered. Exhibit ill-I is an area map showing locations of the facilities that will be used for Midnight Sun development. Drill Sites, Pads, and Roads Use of the E-Pad drill site for the Midnight Sun wells has been selected to (1) eliminate new gravel placement, (2) minimize well stepout to within currently available drilling technology while reaching the extent of the reservoir, and (3) maximize the use of existing facilities. Wells will be drilled between existing IP A wells, eliminating the need to expand the E- Pad. A schematic of the drill site layout is shown in Exhibit ill-2. This schematic shows facilities for a local source water injection system. As an alternative, the Midnight Sun owners are working towards approval to use GC 1 produced water as a water source for the Midnight Sun project. No new pipelines will be required for development of the Midnight Sun reservoir. Midnight Sun production will be routed to GC 1 via existing E-Pad high pressure and low-pressure Page 15 of 41 , it Midnight Sun Pool Rules and AI"í::a Injection Application (' i, June 20, 2000 commonlines. No new roads or roadwork will be required. Drill Site Facilities and Operations Two existing E-Pad production manifold slots and well lines will be used for the Midnight Sun wells. Water for waterflood operations will be obtained from either source water wells drilled at E-pad or produced water delivered by pipeline from GC 1. If the source water system is installed, the source wells would be equipped with electrical submersible pumps (ESPs) to deliver water to the project. The source water injection system option is illustrated in Exhibit 1lI-3. Future gas lift gas will be obtained from an IP A E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. If initial power is needed beyond currently available capacity at E-pad, it will be provided by installing a new 15 kv power line from GCl to the Midnight Sun facilities at E-Pad. All well control at the drill sites will be performed manually by a drill site operator with the exception of the well safety shut in systems (which are automatic) and the drill site emergency shutdown system (which can be triggered manually or automatically). Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. The skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IP A fluids at E-Pad for transport to GC 1. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Production allocation is addressed in Section V. Data gathering at the drill site will be both a manual and automatic function. The data gathering system (SCADA) will be expanded to accommodate the Midnight Sun wells and drill site equipment. The SCADA will continuously monitor the flowing status, pressures, and Page 16 of 41 il" Midnight Sun Pool Rules and\l ..) d Injection Application ( June 20,2000 temperature of the producing wells at the drill sites. These data will be under the drill site operator's supervision through his monitoring station. Midnight Sun production metering will continuously monitor the pressures, temperatures, and flow of the liquid and gas streams. The rate of production from each well will be regulated by manually adjusted chokes. The flow from the wells would be routed to the production metering skid and then to GCl for processing. Production Center No modifications to the GCl production center will be required to process the Midnight Sun production. GCl was built to process a nominal oil rate of 400 MBOPD, gas rate of 320 MMSCFPD (modifications have increased this to 2,600 MMSCFPD) and a produced water rate of 40 MBWPD (modifications have increased this to 85 MBWPD). Production, including that from the Midnight Sun Reservoir, is not expected to exceed existing GC1 capacity. Page 17 of 41 J ~ Midnight Sun Pool Rules and 'hl""d Injection Application ( June 20,2000 IV. Well Operations DRILLING AND WELL DESIGN Two wells have been drilled in the Midnight Sun Pool, E-I00 and E-I0 1. E-l 0 1 is currently producing with plans to convert E-l 00 to an injector. Exhibit IV-I shows the schematic of the E- 100 well. The Midnight Sun depletion plan calls for drilling one additional up structure production well to complete the initial development. If the source water injection system is installed, two shallow source water wells would also be drilled. Midnight Sun wells would be directionally drilled from E-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 Commission requirements will be installed on the conductor. Surface hole would be drilled no deeper than 5,000 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 Midnight Sun wells. Cementing and casing requirements similar to other North Slope fields will be adopted for Midnight Sun. The casing head and a 5,000-psi blowout-preventer stack will be installed onto the surface casing and tested consistent with Commission requirements. 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. Intermediate casings and production liners will be used to achieve specific completion objectives or to provide sufficient contingency in mechanically challenging wells such as high departure wells. To date, H2S has not been detected in any Midnight Sun wells. However, with planned waterflood operations, there is some potential of generating small amounts of H2S over the life of the field. Page 18 of 41 Ii, (.1 L Midnight Sun Pool Rules and Area Injection Application I~ June 20, 2000 Safe drilling practices, to account for the effects of H2S gas on both people and equipment 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. The nature of the wells to be drilled requires the use of E-75, G-I05, or S-135 grade drillpipe. These materials are susceptible to sulfide stress cracking but can be used safely under the controlled conditions recommended in Section 8, "Drill Stem Corrosion and Sulfide Stress Cracking," of API RP 7G, "Drill Stem Design and Operating Limits" which will be used as applicable. WELL DESIGN AND COMPLETIONS Contingent water supply wells would be drilled into the Tertiary interval and completed with a single casing string and downhole electric submersible pumps (ESPs). Open. hole gravel packs would be used in the water supply wells to maximize productivity and prevent sand production. The up structure horizontal producer is planned with a measured depth of over 14,000 ft. and would be completed in the Kuparuk Formation. This departure would necessitate top-setting the Kuparuk. In general, the production casing will be sized to accommodate the desired tubing size in the Midnight Sun wells. The following table indicates the casing and tubing sizes utilized in the proposed well designs for the Midnight Sun wells. Tubing sizes will vary from 3-1/2 to 4-1/2 inches in Midnight Sun wells. Surface Casing Inter I Prod Casing Production Liner Production Tubing Water Supply 9-5/8" N/A N/A 4-112" Horizontal 10-3/4" or 9-5/8" 7 -518" or 7" 4-112" or 3-112" 4-112" or 3-112" I _1:1 "AUIUL-¡ Page 19 of 41 ,} Midnight Sun Pool Rules and ( injection Application ( June 20, 2000 Plans are to run L-80 tubing and casing in these wells. All tubing jewelry will be completed with 9-Cr/lMoly, which is compatible with both L-80 and 13-Cr. All proposed wells call for completion in a single zone, with a single string and a single packer. As shown in the schematic, the wells have gas lift mandrels with dummy valves to provide flexibility for artificial lift if needed to enhance production rates. Sufficient mandrels will be run to provide flexibility for changing well production volumes, gas lift supply pressure, and changes in WOR. SUBSURFACE SAFETY VALVES Subsurface safety valves do not appear to be necessary in the Midnight Sun wells according to statewide regulations (20 AAC 25.265). Existing completions are equipped with SSSV nipples. The up structure producer would be completed in a similar manner. 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 the standard PBU Operator practices. DRILLING FLUIDS In order to minimize skin damage from drilling and to maintain shale stability, water-based KCl mud will be used to drill through the Midnight Sun Pool and nearby shales while low solids, non- dispersed fluids will be used for the upper sections of the well. STIMULATION METHODS Stimulation to enhance productivity or injection capability is not currently planned for Midnight Sun wells. Formation damage associated with drilling and completion activity appears to be Page 20 of 41 ¡i ~ Midnight Sun Pool Rules and Area Injection Application ~ June 20, 2000 minor or insignificant. The use of stimulation in the medium to high permeability rock may be evaluated at a later date. RESERVOIR SURVEILLANCE PROGRAM Midnight Sun data will continue to be collected to monitor reservoir performance and, define reservoir properties. Reservoir Pressure Measurements An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. This 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. The reservoir pressures will be reported at the common datum elevation of 8,050 ft. tvdss. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance (e.g., GOC monitoring and injection profile evaluation). Page 21 of 41 Midnight Sun Pool Rules aJu. r\rea Injection Application (' June 20, 2000 V. Production Allocation Initially, a combination of well tests and wellhead pressure trends will continue to be used to allocate production. Under this methodology, the production from an individual well is first calculated from the average daily wellhead pressure using the deliverability equation. During periods of rising GOR and changing tubing hydraulics, the deliverability equation may not accurately reflect the production as measured by well tests. During such periods, the daily well production is determined by linear interpolation between well test points. A minimum of two well tests per month, as well as lab-measured water cuts and zero-rate tests, are performed on Midnight Sun wells to ensure allocation accuracy. Summing the calculated daily production volume for all producing wells provides an estimate of the Midnight Sun daily field production. A fixed allocation factor of 1.0 is used for Midnight Sun. The long-term metering plan for Midnight Sun is to use continuous production metering. The metering skid described in the Facilities section of this application will be used to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IPA production at E-Pad. Each wellhead will have a continuous two- phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. We request Commission approval under 20 AAC 25.215(a) that the Midnight Sun metering is an acceptable method. An allocation factor of 1.0 would continue to be used with the continuous meter. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. Consistent with existing reporting, no NGLs will be allocated to Midnight Sun. Page 22 of 41 ~' Midnight Sun Pool Rules and Area Injection Application ;1 June 20, 2000 VI. Area Injection Operations This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection to enhance recovery from the Midnight Sun Oil Pool. This section addresses the specific requirements of 20 AAC 25.402(c). PLAT OF PROJECT AREA 20 AAC 25.402(c)(1) Exhibit 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Midnight Sun Oil Pool as of April 1, 2000. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. OPERATORS/SURFACE OWNERS 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) PHILLIPS Alaska, Inc. is the designated operator of the Midnight Sun Participating Area. Surface Owners within a one-quarter mile radius and inclusive of the Midnight Sun Participating Area are as followings: State of Alaska Department of Natural Resources Attn: Ken Boyd P.O. Box 107034 Anchorage, AK 99510 Pursuant to 20 AAC 25.402(c)(3), Exhibit VI-1 is an affidavit showing that the Operators and Page 23 of 41 ~' Midnight Sun Pool Rules anlt Area Injection Application June 20, 2000 Surface Owners within a' one-quarter mile radius of the area of and included within the Midnight Sun Participated Area have been provided a copy of this application for injection. DESCRIPTION OF OPERATION 20 AAC 25.402(c)(4) Development plans for the Midnight Sun Oil Pool are described in Section IT of this application. Drillsite facilities and operations are described in Section ill. If the source water injection system is installed, source water wells will be permitted and constructed in accordance with 20 AAC 25.005. GEOLOGIC INFORMATION 20 AAC 25.402(c)(6) The Geology of the Midnight Sun Oil Pool are described in Section I of this application. INJECTION WELL CASING INFORMATION 20 AAC 25.402(c)(8) The E-I00 Well will be converted to injection service for the Midnight Sun Oil Pool Enhanced Recovery Project. The casing program for this well was permitted and completed in accordance with 20 AAC 25.030. Exhibit IV-I details the completion for the E-I00 Well. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. Conversion of the E-l 00 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 Page 24 of 41 Midnight Sun Pool Rules a~u Area Injection Application I' ~ June 20, 2000 presence of H2S in accordance with 20 AAC 25.065. INJECTION FLUIDS 20 AAC 25.402(c)(9) Type of Fluid/Source The Midnight Sun Enhanced Recovery Project will utilize either GC 1 produced water or water produced from the Tertiary Sagavanirktok formation, as shown in Exhibit VI-2, as an initial and primary water source. Composition Tertiary Water - A water sample from the Tertiary water source interval has not been obtained. However, it is anticipated the water will be of similar composition as water produced from the DS 15-6 Well in the Cretaceous interval. The DS 15-6 Well water composition is shown in Exhibits VI-3. GC1 Produced Water - The composition of produced water from GC1 is shown in Exhibits VI-4. The composition of Midnight Sun produced water will be a mixture of connate water and source injection water. No oil-water contact has been identified in the Midnight Sun Oil Pool and no significant connate water production has occurred or is anticipated. In order to conduct geochemical modeling, the Midnight Sun Oil Pool connate water composition is assumed to be similar to samples from the offset Pt. McIntyre Oil Pool (refer to Exhibit 1-3 in the "Application for Modification to Area Injection Order No.4", dated April 5, 1993). Maximum Injected Rate Maximum water injection requirements at Midnight Sun Oil Pool are estimated at 25,000 BWPD. Compatibility with Formation and Confining Zones Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. Analysis of the E-I01 core indicates low clay content (less than 5% by volume), primarily in the form of kaolinite and illite. No fines migration problems are Page 25 of 41 Midnight Sun Pool Rules a~u. Area Injection Application r( June 20,2000 anticipated. Geochemical modeling results indicate that a combination of Tertiary water and connate water is likely to form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Similar scaling problems are anticipated for GC 1 produced water and connate water. Scale precipitation will be controlled using standard oil field scale inhibition methods. INJECTION PRESSURES 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 2250 psig. The estimated maximum surface injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Projects is 2750 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 Midnight Sun Oil Pool Enhanced Recovery Project well(s) 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 Page 26 of 41 ( Midnight Sun Pool Rules ana Area Injection Application ¡~' :1 June 20, 2000 Formation. Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Enhanced Recovery Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. Fracture propagation models confinn that injection above the parting pressure will not exceed the integrity of the confining zone. The Kuparuk River Formation at the Midnight Sun 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 data for the HRZ and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. No tests have been conducted to determine the formation breakdown pressure at the Midnight Sun Oil Pool; however, data from offset fields suggest that a fracture gradient of between 0.6 and 0.7 psi/ft can be expected in the Kuparuk River Formation at initial reservoir conditions. 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. A tertiary source water system would have an expected surface water injection temperature is 60 - 80°F, resulting in a fracture gradient reduction of .03 to .05 psi/ft. Produced water from GC 1 would have limited impact on the fracture gradient because the water temperature would be close to the Page 27 of 41 t Midnight Sun Pool Rules and Area Injection Application June 20, 2000 reservoir temperature. HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) The Midnight Sun Oil Pool is estimated to have an original oil in place of 40 to 60 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. Page 28 of 41 { Midnight Sun Pool Rules and Area Injection Application f June 20, 2000 VII. Pool Rules Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHll.-LIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Pool Rules for the Midnight Sun Oil Pool. Geology 1. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. 2. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E- 100) well. The well encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. 3. In the E-l 00 well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). 4. Well E-I0l (Midnight Sun #1) was drilled as a down structure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-l 00 well. 5. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. The Kuparuk Formation can be divided into upper and lower units. In the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fine to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. 6. The Midnight Sun Pool is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. 7. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural dip is less than 2 degrees. 8. The Midnight Sun accumulation is a combination structural/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Page 29 of 41 ( Midnight Sun Pool Rules and Area Injection Application { June 20, 2000 Formation thickness are fault movement and erosional truncation. 9. The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, based on Repeat Formation Tester (RFT) data. 10. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. 11. Heavy oil was encountered at 8,107 ft. tvdss in the E-IO 1 well. Conventional core from the E-l 0 1 well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Reservoir Description and Development Planning 1. Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-I0l core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. 2. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-I0 1 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. 3. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in the lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. 4. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-I0l core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.60/0. 5. Based on RFT data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit. 6. Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-I01 well. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil- ratio (GOR) of 717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. 7. The Midnight Sun Pool contains an estimated Original Oil In Place (OOIP) of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. 8. Production of the Midnight Sun Pool commenced in October of 1998. Early production from the E-I00 Well was restricted to mitigate gas coning, and is currently shut in to limit reservoir voidage. Page 30 of 41 ( Midnight Sun Pool Rules anu Area Injection Application !¡!(. June 20, 2000 9. Production from well E-I0l demonstrates gas under-running. In January of 1999, the E-I0l well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. 10. A reservoir model of the Midnight Sun Pool was constructed and history matched to evaluate development options, and reservoir management practices. 11. Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) upstructure gas injection, and 3) waterflood. 12. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP 13. Model results indicate that upstructure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI) and 27% after 2.0 HCPVI. The vertical sweep efficiency for upstructure gas injection is poor, showing low recovery in the lower Kuparuk unit. 14. Several waterflood development options were studied using the Midnight Sun reservoir model including upstructure, downstructure, and midfield water injection. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-I00 well to injection service. The midfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. 15. Based on reservoir model studies, the recommended development plan involves implementation of a midfield waterflood for the Midnight Sun Pool. The planned development well program includes the addition of one upstructure horizontal production well to complete a three well development of the Midnight Sun Pool. 16. The development plan results in a nominal spacing of 280 acres for the three well development, however the operator has requested a minimum well spacing of 80 acres. 17. Gas cap expansion will provide initial pressure support prior to waterflood start-up. 18. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. 19. Following waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. Page 31 of 41 ~ Midnight Sun Pool Rules ana Area Injection Application ~, June 20, 2000 20. Model results indicate that oil flux into the gas cap will occur as a result of the low structural relief. Reservoir surveillance and voidage management will mitigate oil flux to the west of the up structure horizontal producer. 21. Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated Facilities 1. Midnight Sun wells will be drilled from the E-Pad drill site and make use of existing IP A infrastructure. 2. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E-Pad and then transported to Gathering Center 1 (GC1) for treatment and shipment to Pump Station No.1 (PS-1). 3. Water for waterflood operations will be obtained from two source water wells equipped with electrical submersible pumps or via pipeline from GC 1. 4. Future gas lift gas will be obtained from an IP A E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. 5. Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. 6. The continuous metering skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IP A fluids at E-Pad for transport to GC 1. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Well Operations 1. Additional Midnight Sun Pool development wells will use drilling procedures, well design, and casing and cementing programs consistent with those currently used in other North Slope fields. 2. All proposed wells call for completion in a single zone, with a single tubing string and a single packer Page 32 of 41 "I' ~ Midnight Sun Pool Rules ana Area Injection Application I( June 20, 2000 3. Sub-Surface Safety Valves (SSSV) are not installed in existing Midnight Sun, and are not planned for additional wells, however, nipples are installed to allow flexibility to install wireline retrievable SSSV s. 4. Surface safety valves are included in the wellhead equipment of existing Midnight Sun Pool wells. Testing of SSVs will be in accordance with the standard PBU Operator practices. 5. Stimulation to enhance productivity or injection capability IS not currently planned for Midnight Sun wells. 6. An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. A pressure datum elevation of 8,050 ft. tvdss is recommended. Production Allocation 1. Initially, a combination of well tests using the E-Pad facilities and wellhead pressure trends will continue to be used to allocate production. The daily well production is determined by linear interpolation between well test points. 2. A continuous production metering skid will be installed to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IP A production at E- Pad. 3. Each wellhead will have a continuous two-phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. An allocation factor of 1.0 would continue to be used with the continuous meter. 4. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. PROPOSED CONCLUSIONS PHll...LIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. Commercially exploitable hydrocarbons are present in the Midnight Sun Pool, contained within Kuparuk River Formation. 2. Pool rules for the development of the Midnight Sun reservoir are appropriate at this time. Page 33 of 41 (' Midnight Sun Pool Rules ana Area Injection Application ( June 20, 2000 3. An integration of interests for the area contemplated for development by the operator exists between the working interest owners and royalty owners. 4. The vertical limits of the Midnight Sun reservoir may be defined in the E-IOO well which appears to be a typical and representative well. 5. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. 6. Waterflood operations are planned and appear to achieve the greatest ultimate recovery of oil. 7. Other than establishing setting depths, the operator is not requesting variance from statewide casing and cementing requirements. 8. The E-Pad drillsite is an onshore location. 9. Subsurface safety valves are not required by statewide regulations. 10. Surface commingling of Midnight Sun production with IP A and other Prudhoe satellite production will increase ultimate recovery, will not cause waste nor jeopardize correlative rights. 11. The Midnight Sun continuous metering plan is an acceptable method of allocating produced fluids back to the Midnight Sun Pool for revenue and reservoir management purposes. 12. Appropriate reservoir surveillance data will be obtained to complete development and conduct appropriate reservoir management. 13. The operator has demonstrated that primary depletion, supported by gas cap expansion, does not adversely impact ultimate recovery as long as waterflood operations commence before the reservoir pressure drops below 3300 psi at the reservoir datum. 14. Exception to the gas-oil-ratio limit of 20 AAC 25.240(b), is appropriate at this time. PROPOSED RULES PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following Pool Rules for the Midnight Sun Oil Pool: Subject to the rules below and statewide requirements, production from the Midnight Sun reservoir 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. Page 34 of 41 I' Midnight Sun Pool Rules at... Area Injection Application ¡! (Ii June 20, 2000 In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Midnight Sun Pool. Rule 1: Field and Pool Name and Classification The field is the Prudhoe Bay Field and the pool is the Midnight Sun Pool. The Midnight Sun Pool is classified as an Oil Pool. Rule 2: Pool Definition T12N-R13E: Sec 25, S 1/2; Sec 36, N1/2, SE1/4, E1/2 of SW1/4 T12N-R14E: Sec 29, ALL; Sec 30, S1/2, S1/2 ofNE1/4, S1/2 of NW1/4; Sec 31, N1/2, SW1/4, N1/2 of SE1/4; Sec 32, NW1/ 4 T12N-R14E: Sec 28, W1/2, W1/2 ofNE1/4, W1/2 of SE1/4 The Midnight Sun Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 11,662 and 11,805 feet in the E-100 well. Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer than 300 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 at six-month intervals. Rule 5: Common Production Facilities and Surface Commingling (a) Prior to installation of a continuous metering skid, producing Midnight Sun wells will be tested a minimum of 2 times per month and production will be allocated by interpolating between well test results. (b) After installation of the continuous metering skid, the requirements of 20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Pool as a whole, and then allocating that production to each well daily. (c) The allocated production for the Midnight Sun Pool will not be adjusted in conjunction with the IP A allocation factors (i.e. the Midnight Sun allocation factor will be 1.0). (d) The operator shall submit monthly reports containing daily production metering and daily well allocations. Page 35 of 41 (' Midnight Sun Pool Rules and Area Injection Application June 20,2000 Rule 6: Reservoir Pressure Monitoring (a) A minimum of one bottom-hole pressure survey will be taken annually for the Midnight Sun Pool. (b) The reservoir pressure datum will be 8,050 feet true vertical depth subsea. (C) Pressure surveys may 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. (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 Midnight Sun 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 3300 psi at the datum or within 2 years 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 any other special monitoring. 4. Future development plan. The report will be submitted to the Commission by the end of first quarter of 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. Page 36 of 41 ( Midnight Sun Pool Rules anu Area Injection Application ( June 20, 2000 VIII. Area Injection Application Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Area Injection Order for the Midnight Sun Oil Pool. 1. The reservoir interval containing the Midnight Sun Oil Pool is the Kuparuk River Formation. 2. Production from the Midnight Sun Oil Pool commenced in October of 1998. There are currently two wells in the Midnight Sun Oil Pool. The location and mechanical configuration of these wells are identified in the application. There are currently no injection wells in the Midnight Sun Oil Pool. 3. Initial enhanced recovery plans for the Midnight Sun Oil Pool call for conversion of one well, E-I00, to water injection. Water injection is expected to commence in the third quarter of 2000, with a nominal design injection rate of 20-25,000 BWPD. 4. Operators and Surface Owners within a one-quarter mile radius of the area included in the Midnight Sun Participated Area have been provided a copy of this application for injection. 5. Injection water for the enhanced recovery project will be obtained from either source water wells or will utilize produced water from GC 1. If a source water system is installed, source wells would be drilled and equipped with electrical submersible pumps (ESPs) to deliver water to the project. 6. An initial three well development program is contemplated, with midfield water injection at the E-I00 Well, and the addition of one upstructure horizontal producer. Additional injection and production wells may be considered depending on reservoir performance and ongoing technical evaluation. 7. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15 to 25% of the estimated 40-60 MMSTB original oil in place, relative to primary depletion driven by gas cap expansion. 8. The casing program for the E-l 00 Well was permitted and completed in accordance with 20 Page 37 of 41 l Midnight Sun Pool Rules and Area Injection Application ( June 20, 2000 AAC 25.030. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. All injection casing is cemented and tested In accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. 9. Estimated maximum and average injection pressures (psig) for the Midnight Sun Oil Pool are 2250 psig and 2750 psig, respectively. 10. Following waterflood start-up, the voidage replacement by water injection will exceed offtake to suppress gas production and restore reservoir pressure. A balanced voidage replacement will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. 11. Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. 12. Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. 13. The expected maximum injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Project welles) will not initiate or propagate fractures through the confining strata (Kalubik and HRZ shales), and, therefore, will not allow injection or formation fluid to enter any freshwater strata. 14. There are no freshwater strata overlying the proposed area for this enhanced recovery project. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. The requirements of 20 AAC 25.402, and 20 AAC 25.460 have been met for the injection of water for the proposed Midnight Sun Oil Pool enhanced recovery operations. 2. Establishment of a new Area Injection Order for the Midnight Sun Oil Pool area will not cause waste nor jeopardize correlative rights, and is based on sound engineering principles. 3. No underground sources of drinking water (USDW) are known to exist in the Western Operating Area of the Prudhoe Bay Unit, including the proposed Midnight Sun Oil Pool. 4. Authorizing injection of water for enhanced recovery operations in Midnight Sun Oil Pool is Page 38 of 41 ~' Midnight Sun Pool Rules and Area Injection Application ( June 20, 2000 appropriate and in accordance with sound engineering principles. 5. Injection operations in the Western Operating Area of the Prudhoe Bay Unit, and the Midnight Sun Oil Pool will be conducted in permeable strata which can reasonably be expected to accept fluids at pressures less than the fracture pressure of the confining strata. 6. Specific approvals to convert or drill injection wells will be required. PROPOSED RULES PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class IT fluids for enhanced oil recovery in the Midnight Sun Pool and consider the following rules to govern such activity: Affected Area: TI2N-RI3E: See 25, S1I2; Sec 36, N1I2, SE1I4, E1I2 of SW1I4 TI2N-RI4E: Sec 29, ALL; See 30, SI/2, S1I2 ofNE1I4, S1I2 of NW1I4; Sec 31, N1I2, SW1I4, N1I2 of SE1I4; Sec 32, NW1I4 TI2N-RI4E: Sec 28, W1I2, W1I2 ofNE1I4, W1I2 of SE1I4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, Class IT fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formation found in the E-l 00 Well between the measured depths of 11,662-11,805 feet. Rule 2: Fluid Injection Wells The injection of fluids must by conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; or 2) through an existing well that has been 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 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. Page 39 of 41 ( Midnight Sun Pool Rules and Area Injection Application If June 20, 2000 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 by the vertical depth of the packer, whichever is greater, but not to exceed a hoop stress greater than 700/0 of the casing's minimum yield strength must be held for at least a 30 minute period with decline no more than or equal to 100/0 of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever disposal rates and/or operating pressure observations 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 FOnTI 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: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering principles, and will not result an increased risk of fluid movement into an USDW. Page 40 of 41 ~' Midnight Sun Pool Rules and Area Injection Application June 20, 2000 IX. Exhibits Exhibit 1-1 Location Map of Midnight Sun Pool Exhibit 1-2 Midnight Sun Participating Area Exhibit 1-3 Type Log (E-I00) - Kuparuk Interval Exhibit 1-4 Top Kuparuk Structure Map for Midnight Sun Pool Exhibit 1-5 Kuparuk Isochore Map for Midnight Sun Pool Exhibit 1-6 East-west well structural cross-section along axis of Midnight Sun Pool Exhibit 1-7 North-south well structural cross-section across Midnight Sun Pool Exhibit 1-8 Net sandstone map for Midnight Sun Pool Exhibit 1-9 Gross hydrocarbon distribution map for Midnight·Sun Pool Exhibit 11-1 Fluid Property Summary for the Midnight Sun Pool Exhibit 11-2 Pressure- V olume- Temperature (PVT) Properties as a Function of Pressure Exhibit 11-3 Reservoir Model Layering and Average Physical Properties Exhibit II -4 Comparison of Model Predictions and Field Performance Exhibit 11-5 Production and Recovery Profiles for Primary Depletion Exhibit 11-6 Production and Recovery Profiles for Up structure Gas Injection Exhibit 11-7 Production and Recovery Profiles for Waterflood Exhibit 111-1 Facility Location Map Exhibit 111-2 Drill Site Schematic Exhibit 111-3 Source Water Injection System Exhibit IV -1 E-I00 Wellbore Schematic Exhibit VI-l Affidavit of Notification Exhibit VI-2 Shallow Section Type Log E-16 - Source Water Intervals Exhibit VI-3 DS 15-6 Produced Water Sample Analysis Exhibit VI-4 GC #1 Produced Water Sample Analysis Page 41 of 41 #9 ) ) ALASKA OIL AND GAS CONSERVATION COMMISSION June 13,2000 9:00 AM PUBLIC HEARING - MIDNIGHT SUN NAME - AFFILIATION TELEPHONE (PLEASE PRINT) ---i, J/G...~-¡-p¡- ß1-I-;,.o~ Iv1~HA'-<-tJ~ç.~ ('- ..=:J I A.A... l..' c5) Lr..J 1À~ 2c,.~&g46 Z & <:,': G. cçC{ 'í 'L.ÓG- B'""f~~ r1)J.~~ L I - t ~~j Q,v.u...JJ ~ ~ ,~ Do you ulan to testify? Yes No ~~ t/l.Q ÙO #8 :;.wd: Agency Questions Regarding the Midnight Sun) )RuleS and AIOApplication] ) Subject: [Fwd: Agency Questions Regarding the Midnight Sun Pool Rules and AIOApplication) Date: Mon, 19 lun 2000 13:37:33 -0800 From: Robert Crandall <Bob _ Crandall@admin.state.ak.us> Organization: DOA-AOGCC To: "Davies, Steve" <steve_davies@admin.state.ak.us>, "Mahan, Wendy" <wendy_mahan@admin.state.ak.us>, "Maunder, Thomas" <tom _ maunder@admin.state.ak.us>, "Oechsli, Camille" <cammy _ oechsli@admin.state.ak.us>, "Seamount, Dan" <dan _ seamount@admin.state.ak.us>, "W ondzell, Blair" <blair _ wondzell@admin.state.ak.us> These are the responses to the questions we drafted after reviewing the midnight sun testimony. These answers are complete and I feel address our concerns. Combined with the testimony already submitted I do not foresee any outstanding issues related to wednesday's hearing, let me know if you feel different. I'll be out of the office on thursday 6/22 cheers RPC L:,,, "'''''' .....",.....".....,..',,,..,......,...,'..........,,.......,......'.,,... ....... ..................,.."............. ,',...... ................,..... ...,......",.....,....,'..',........... ..,............,.".......,........,.. .".....""."..... '''''''''''''''''''' Subject: Agency Questions Regarding the Midnight Sun Pool Rules and AIO Application Date: Mon, 12 lun 2000 15:39:41 -0900 From: "Carl E Lundgren" <CLUNDGR@ppco.com> To: bob _ crandall@admin.state.ak.us Bob, Attached are the Q&A's. Carl ---------------------- Forwarded by Carl E Lundgren/AAI/ARCO on 06/12/2000 03:38 PM --------------------------- ERIC W REINBOLD 06/12/2000 02:40 PM To: Jack Hartz@admin.state.ak.us cc: (bce: Carl E Lundgren/AAI/ARCO) Subject: Agency Questions Regarding the Midnight Sun Pool Rules and AIO Application Jack- The enclosed document contains answers to the question identified by the AOGCC in your review of the application. We will be prepared to answer these, or related questions, at the hearing next week. If you need any clarification, please don't hesitate to call me at 263-4465. (See attached file: AOGCC MS Q&As.doc)] Thanks! Eric Reinbold PHILLIPS Alaska, Inc. 10f2 7/18/0010:00 AM 'wd: Agency Questions Regarding the Midnight Sun I )Rules and AIOApplication) . , " ) 1....... '..W uN \v " ...... ...".." "",..""""..,,,,,,,...,.. ....."" ...,..." '''''''''''''''''''' "... . "............"....."..............."....,,,...........,.... ,.""" .·.....oo .............".,,,,,...,,...,,, """""""""'"'''''''''''''''''''''' ..."".."........ ..,.,,,,,.,..,,,....,,' . . Name: AOGCC MS Q&As.doc ~AOGCC MS Q&As.doci Type: Microsoft Word Document (application/msword)¡ . Encoding: base64 ! 'Description: Mac Word 3.0 ..... ..... .... ""I' ......~I".·" ...... ...... "'..,..·..···"/1,....·....·1/·..··.......·........· .. ..···..·......·11....'..·......":.'1111.....·..··"·:1..'..·..· '" ,. ...."...~ ., ....... ') 7/18/00 10:00 AM ) ) Midnight Sun Pool Rules and AIO Application AOGCC Q&As Has there been any more work done to quantify the volume of heavy oil relative the the lighter oil volume? No. An additional downstructure well would be required to define the distribution of the heavy oil. At this point, no additional downstructure development is anticipated. What is the magnitude of the shift in heavy oil contact made to achieve a better history match? How did the volume of light oil change with the shift of the HOC? The heavy oil contact was shifted from 8107' TVD-SS to 8111' TVD-SS to increase downstructure pore volume. The deeper contact increased the light oil OOIP 3 MMstb. A gas sample analysis should be included if one is available. If no analysis is available, provide the properties derived from correlation or analogs. Compositional analysis of the E-101 separator gas was performed in conjunction with the routine PVT study. The PVT report has be provide to the agency. What surveillance methods are being considered to monitor or estimate oil flux into or toward the gas cap? You may want to state how reservoir management will be used to prevent oil flux into the gas cap. Oil flux west of the upstructure producer will be limited by managing voidage replacement. After achieving a target reservoir pressure of 3800 to 4000 psi, theVoidage Replacement Ratio (VRR) will be maintained at 1.0, to fully replace voidage, while limiting any out of pattern flux. The voidage replacement balance will be monitored monthly. Additionally, annual reservoir pressure measurements will be used to insure that a balanced voidage replacement is being achieved. Is there any evidence of communication through the reservoir, i.e., interference the between production well and the shut in well? Yes. A pulse test was conducted in January of 1999 that confirmed continuity between Wells E-100 and E-101. Subsequent to this determination, Well E-100 has been utilized as the observation well to monitor reservoir pressure decline associated with downstructure production. During fillup, do you expect gas to resaturate the oil as the average pressure increases? Yes, to a degree. As pressure declines, evolved gas remains immobile until the critical gas saturation is achieved. At this point, gas will migrate upstructure, accumulating under barriers or coalescing with the overlying gas cap When waterflood is implemented and reservoir pressure begins to increase, any gas that remains in close association with oil will resaturate the oil. In contrast, gas that moves upstructure will be effectively removed from the oil and not be available for resaturation. 07/18/00 Page 1 of 1 #7 Midnight Sun Prepared Testimony Feedback ) ,) Subject: Midnight Sun Prepared Testimony Feedback Date: Thu, 25 May 200008:42:47 -0700 From: Jack Hartz·<jack_hartz@admin.state.ak.us> lnternal Organization: Alaska Oil and Gas Conservation Commission To: John W Groth <JGROTH@ppco.com> cc: Daniel T Seamount JR <dan_seamount@admin.state;ak.us>, Camille Oechsli <cammy _ oechsli@admin.state.ak.us> John Groth Development Supervisor.. Eastern North Slope Phillips Alaska, Inc. John, Staff at the AOGCCreviewed the subject testimony and have only a few comments or questions. Your staff may wish to add to the testimony or be prepared to answer possible questions along these lines during the hearing. Has there been any more work done to quantify the volume of heavy oil relative the the lighter oil volume? What is the magnitude of the shift in heavy oil contact made to achieve a better history match? How did the volume of light oil change with the shift of the HOC? A gas sample analysis should be included if one is available. If no analysis is available, provide the properties derived from correlation or analogs. What surveillance methods are being considered to monitor or estimate oil flux into or toward the gas cap? You may want to state how reservoir management will be used to prevent oil flux into the gas cap. Is there any evidence of communication through the reservoir, i.e., interference the between production well and the shut in well? During fillup, do you expect gas to resaturate the oil as the average pressure increases? The overall application package was quite informative and well laid out We look forward the the hearing. Any questions, call myself, Bob Crandall, Steve Davies or Tom Maunder on operations issues. Jack Hartz I,...,.... Jack Hartz <Jack Hartzcmadmin.state.ak.us> Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission lof2 6/20/00 1 :22 PM #6 ) ) Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Midnight Sun Pool, Prudhoe Bay Field - Pool Rules and Area Injection Order PHILLIPS Alaska, Inc. by letter dated May 3, 2000, has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 and 20 AAC 25.460 to hold a public hearing to present testimony to establish pool rules and an area injection order for the Midnight Sun Pool, Prudhoe Bay Field, on the North Slope of Alaska. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 AM on June 13, 2000, in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. 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 Diana Fleck at 793-1221 before June 6, 2000. Ca~ lQcv,-,~,-j«'f'L- Camillé Oechsli Taylor Commissioner Published May 10. 2000 ADN A0020 1403Ú Ii Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AI< 99508 AD# DATE PURCHASE ORDER EDITION ACCOUNT 381261 5/10/200 STOF0330 02014036 DN STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, 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 language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was puólished 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 saId period. That the full amount of the fee charged for the fore~oing publication is not in excess of the rate charged private indIviduals. Signed~-cLfu- ~ Subscribed and sworn to me before this date: 6/;/)/60 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: I ~ Þ !o I 4/7~~~??~ / ~~:' 01AR;·t~ '- . ~ --- . =. := PU8L'" ~ ';::. _s· ...... - ".d'A ......... ¿So ß::::; -- ~ ':-v. ~.... 'V."- ~ ~o. ~ Of þ.\.:.,.. '\..--\" ........... .00..· ~.>'" /.// 'E~P'¢ \\\\ )})})..JJJJ}\' " ",', '. "',,,. .,~~ ~!"~" ,,',', ,r ,¡..:"," If""]' ~,: '-I( I; : :'","" f .. 1~""D ~ 'i, I¡" II...../, ~ '~ I" I '\1~ i 'fì ,;I' L ' l,qiT '." I ~,~'~:rr 111" !Q"'fr:'¡;>', ~;tô.1' ,~4A Y 22 2000 /\~,t3}~a O'¡¡ J1. C,êß Con;:;. CCimm;s:sion /.\nshnr~~Qe ~ ~f}D ;f PRICE PER DAY $65.79 $65.79 ~oti~~ O,f PubUc Hè,arin9 " STATE OF ALASKA Alaska Oil and Gas Conservation , Commls$ion Re: Midnight S.un'P,Qol. Prudhoe ,Bay Field - Pool Ru lesa n;dAreøl nj ect.ion· Order " . PI::tIILLlPS Älaska,lIk.bY letter dated May,3, 2.o.o.o¡ has petitioned .theAlaska Oil and Gas Consèrvat.ion Comrnissionunder 2.oÄAG 2'5.52.0 and 2.0 AA.C:25.46.o to hold apuÞJic. hea~H,gtò presenttest.imony to .estab- t;',h e,jC, I r'jl"s and an ('1reo I ,r.i.;r::TI':Ir"1 "r(l~" r",r'" 1n.:, I'.'\"J. ~'a3;"F¡~'i"d/P~~1 t:~r~üO~~h Slope of Alas.kå. . ' A heari~g will be.hèl¡:1qt the AlaskoOil àndGçs ConservatiOn. Commission I 3.0.01 P.orcupinè Driv~~.An- chQrage, A.lo'ska 995.o1,ot 9:.o.oAM.on.June 13/2.0.0.0, in COhformanc~ with 2.0 AA,'c 25.54.0. .AII.. interested pe~: sons and'parties'are in- vited to present testimony. If yoU are á person witha di~~b,ll¡tYWhO moy'·n~:ec;\. special accommodation In order to comment orto at- I tend the p'Ublichearing, please contact Diana Fleck ¡ ~J.oÒ29~1221 beforeJune ~/ , Is/CamilleOechsli Toylor i Commissioner : AO-.o2.o14.o36 1 Pub.: Mby 1.0/ 2.0.0.0 #5 ¿ 'f. r )[j/1 PHilliPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 3, 2000 Robert N. Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99502-3192 Re: Request for Hearing: Midnight Sun Oil Pool, Pool Rules and Area Injection Application Dear Mr. Christenson: PHILLIPS Alaska, Inc. ("PHILLIPS"), in its capacity as Midnight Sun Operator for itself and on behalf of Exxon Mobil Corporation ("Exxon Mobil") and BP Exploration (Alaska), Inc. ("BPX"), requests that the Commission schedule a public hearing to consider the Midnight Sun application for pool rules and area injection order. We request that you schedule the hearing for a day that is convenient for the Commission in June. Enclosed is the complete application. Please contact E. W. Reinbold (263-4465) if you have any questions or require additional information. Sincerely, ~~ J. W. Groth cc: D. W. Bose (PHILLIPS) M. P. Evans (ExxonMobil) J. Hurliman (BPX) RECEJ\fED i .,,\'( 04 2000 Alaska Oil & Gas Coos. Commission Anchorage, I I I I I I I I I I I I I I I I I I I Midnight Sun Oil Pool Pool Rules And Area Injection Application May 3, 2000 RECE\VED ¡ :.~:( 0 4 200() k on & Gas Cons. Commission A\as a Anchorage I I I I I I I I I I I I I I I I I I I ,,- ~ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Table of Contents 1. Geology p. 1 II. Reservoir Description and Development Planning 5 III. Facilities 15 IV. Well Operations 18 V. Production Allocation 22 VI. Area Injection Operations 23 VII. Pool Rules- Proposed Findings, Conclusions, and Rules 29 VIII. Area Injection Application - Proposed Findings, Conclusions, and Rules 37 IX. Exhibits 41 I I I I I I I I I I I I I I I I I I I ~ Midnight Sun Pool Rules and Area Injection Application 'i May 3, 2000 I. Geology Introduction The Midnight Sun Pool is located on Alaska's North Slope, as illustrated in Exhibit 1-1. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E-100) well. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. The E-100 well is the first well to encounter the Kuparuk River Formation in this area. The Fawn Lake #1, Abel State #1, North Prudhoe Bay State #1 and #2, North Prudhoe #3, Term Well A wells, and wells drilled from nearby pads in the Prudhoe Bay Field did not encounter the Kuparuk River Formation. Exhibit 1-2 shows the location of the Midnight Sun Participating Area (MSPA). Development drilling will utilize the existing gravel E-pad, from which the E-100 discovery well was drilled. One delineation well, the Midnight Sun #1 (E-101), was drilled from E-pad in October 1998 to confirm the extent of the Midnight Sun discovery. Stratigraphy The Midnight Sun Pool is composed of the Kuparuk River Formation, also informally referred to as the "Kuparuk Formation". This formation was deposited during the lower Cretaceous geologic time period, between 153 and 115 million years before present. Exhibit 1-3 shows a portion of the open hole electric logs from the E-100 well. This "type log" illustrates the stratigraphic definition of the Midnight Sun Pool. The log is scaled in true vertical depth subsea (tvdss) and also has a measured depth (md) track. In the E-100 well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). This is also the productive interval of the Midnight Sun Pool. The Kuparuk Formation base is defined by its contact with the Jurassic-age Kingak Formation as Page 1 of 41 I I I I I I I I I I I I I I I I I I I III' ~ Midnight Sun Pool Rules and Area Injection Application f May 3, 2000 seen with a change in lithology and conventional electric log character. The Kingak Formation is a shale with low resistivity (1 to 3 ohm-meters). The Kuparuk Formation is composed of medium- to fine-grained quartz-rich to glauconitic sandstone with higher resistivity (3-50 ohm- meters). The Kuparuk Formation top is defined by its contact with the lower Cretaceous-age High Radioactive Zone (HRZ) Formation as seen by a change in lithology and conventional electric log character. The HRZ is a black, organic-rich shale recognized by the gamma ray log, typically greater than 150 gamma API units. The Kuparuk Formation in the Midnight Sun Pool is stratigraphically complex, characterized by rapid change in thickness, sedimentary facies and local diagenetic cementation. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. As shown on the type log in Exhibit 1-3, the Kuparuk Formation can be divided into upper and lower units. The basal portion of the lower unit in E-I0l is a non-productive, tight, glauconitic sandstone with minor amounts of shale rip-up clasts. This unit was not encountered in E-IOO and is assumed to be restricted to the area near E-I0 1. Moving up in the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fme to fine- grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. The sands in the upper unit are poorly to well- sorted. Intergranular siderite cement is common in the upper unit and plays an important role in determining reservoir quality. Cementation is especially abundant in the lower portion of the upper unit where it degrades reservoir quality. The upper and lower units have distinctly different thickness trends. The lower unit maintains a nearly uniform thickness throughout the Midnight Sun area, suggesting that its deposition predates significant fault movement. In contrast, the thickness and lithology of the upper unit are variable and have been influenced by syn-depositional faulting. Page 2 of 41 I I I I I I I I I I I I I . I I I .. I <{ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Structure Exhibit 1-4 is a structure map on the top of the Kuparuk Formation with a contour interval of 20 feet. Top Kuparuk structure in the Midnight Sun area is characterized by a bowl-shaped depression gently dipping to the northeast. The Midnight Sun depression is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural highs surrounding the Midnight Sun accumulation are devoid of Kuparuk. Formation rock. Along the axis of the depression, the structural dip is less than 2 degrees, down to the northeast. Exhibit 1-5 is an isochore map of the Kuparuk Formation with a contour interval of 10 feet. The Midnight Sun accumulation is a combination structura]/stratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Formation thickness are fault movement and erosional truncation. Kuparuk Formation deposition occurred in marine shoreface and deltaic depositional environments. Exhibit 1-6 is a structural cross-section along the axis of the Midnight Sun structural depression (see Exhibit 1-1 for location). This cross-section illustrates the western and eastern limits of the Midnight Sun Pool. The western limit of the pool is fault-controlled by the Prudhoe Mid-Field fault and the eastern boundary is a stratigraphic truncation of the Kuparuk Formation onto the North Prudhoe structural high. Exhibit 1-7 is a north-south structural cross-section through the Midnight Sun Pool (see Exhibit 1-1 for location). This exhibit illustrates the fault-bounded isolation of the Kuparuk Formation on the north by the Sambuca fault and on the south by the Prudhoe bounding fault system. Fluid Contacts The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, Page 3 of 41 I I I I I I I I I I I I I I I I I I I l' ,t Midnight Sun Pool Rules and Area Injection Application May 3, 2000 based on Repeat Formation Tester (RFf) data. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. Based on core water saturation data and Mercury Injection Capillary Pressure data, the reservoir is interpreted to be significantly above the effective OWC. ' Heavy oil was encountered at 8,107 ft. tvdss in the E-101 well. A heavy oil sample, measuring 10 degrees API gravity, was recovered by the RFf at 8,107 ft. tvdss. Conventional core from the E- 101 well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Pool Limits The trap for oil and gas in the Midnight Sun Pool is created by a combination of structural and stratigraphic features. To the south, west, and north, the pool limit is defined by the juxtaposition of the reservoir against the impermeable Kingak. shale across the Prudhoe bounding fault system, Prudhoe Mid-Field fault, and Sambuca fault, respectively. Stratigraphic truncation of the Kuparuk Formation forms the trapping mechanism to the east. The boundaries of the Midnight Sun P A encompass the proposed boundaries of the Midnight Sun Pool. Exhibit 1-8 is a net sandstone map of the Midnight Sun Pool with a contour interval of 2- feet. Exhibit 1-9 is a gross hydrocarbon distribution map of the Midnight Sun Pool. Page 4 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and Area Injection Application May 3, 2000 II. Reservoir Description and Development Planning ROCK AND FLUID PROPERTIES The reservoir description for the Midnight Sun Pool is based on core data from the E-I0 1 well and log data from the E-l00 (Sambuca #1) and E-I0l (Midnight Sun #1) wells. Well E-I01 was cored through the entire Kuparuk section with water based mud and low invasion coring techniques. The core data were used to calibrate the petrophysical log model, which was used to construct the Midnight Sun geologic model. Porosity and Permeability Core porosity and permeability measurements were conducted at overburden pressure and permeability was corrected for gas slippage (Klinkenberg correction). Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-I01 coredata. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-I0 1 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean permeability is 760 md. The ratio of vertical to horizontal permeability ranges from 0.2 to 1.0 in the upper Kuparuk Formation and from 0.6 to 1.0 in the lower Kuparuk Formation. Net Pay Net pay was determined based on visual inspection of the E-101 core in conjunction with review of thin section and routine core analysis data. The Kuparuk Formation in the Midnight Sun Pool has very low clay content, generally less than 2% by volume, and no defined shale sections. In the upper Kuparuk Formation, reservoir volume is reduced by the presence of discontinuous, nodular and banded siderite and glauconite. These mineral inclusions were identified visually, and the net- to-gross-ratio was determined based on the ratio of reservoir quality sand to gross rock area exposed on the slabbed core. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in the Page 5 of 41 I I I I I I I I I I I I I I I I I I .~. Midnight Sun Pool Rules and Area Injection Application May 3, 2000 lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. Water Saturation Water saturation data were measured throughout the Kuparuk Formation interval in the E-I01 low invasion core. A chemical tracer confirmed that the core experienced nllnimal invasion. Water saturation data were corrected for mud filtrate invasion based on the tracer results. Water saturation measurements from the core were then used to calibrate the petrophysical log model. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-101 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. Water saturation data derived from the core and log data were used to develop Leverett J- functions, which were subsequently translated to drainage capillary pressure curves for the upper and lower Kuparuk Formation intervals. The capillary pressure data were then used to initialize water saturation in the reservoir model based on capillary pressure equilibrium. Relative Permeability A steady state water-oil relative permeability experiment was conducted on a composite core from the upper Kuparuk Formation interval. The residual oil saturation from this displacement experiment was 22.7%. Centrifuge water-oil and gas-oil experiments were also conducted. Results from these experiments indicate that water-oil relative permeability measurements for the Midnight Sun Pool are similar to those measured for other North Slope fields exhibiting favorable waterflood performance. In the absence of having an extensive data set for all relative permeability functions, analog data sets were used for performance predictions. Initial Pressure & Temperature Based on RFT data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit at the datum. Page 6 of 41 I I I I I I I I I I I I I I I I I I I ~. Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Fluid PVT Data Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-IOl well. The sample was recombined to the bubble point pressure of 4045 psia, corresponding to the pressure at the GOC at initial conditions. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil-ratio (GOR) of 717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. Exhibit II-I shows a summary of the fluid property information for the Midnight Sun Pool. Exhibit II-2 contains a listing of the various pressure-volume-temperature (PVT) properties as a function of pressure. Hydrocarbons in Place Estimates of hydrocarbons in place for the Midnight Sun Pool reflect current well control, stratigraphic and structural interpretation, and rock and fluid properties. These data were integrated in the construction of a fine scale geologic model, which provides the basis for estimation of original fluids in place. The results indicate an Original Oil In Place (OOIP) range of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. RESERVOIR PERFORMANCE Well Performance Two wens (E-I00, and E-I0l) have been drilled and completed in the Kuparuk formation. Both wells are tied into the Prudhoe Bay E-Pad facilities. Production commenced in October of 1998. \Ven E-l00 (Sambuca #1), the discovery well, encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. The well was perforated over a 20 feet interval at the base of the reservoir. The initial production rate was 2,000 to 3,000 BOPD with a GOR of approximately 950 scf/stb. The rate was restricted to mitigate coning, although the GOR increased steadily to 6000 scf/stb during the first three months of production. The well is currently shut in to limit reservoir voidage. Page 7 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Well E-101 (Midnight Sun #1) was drilled as a downstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the GOC identified in the E-100 well. No oil-water contact was identified by open-hole logs. The initial production rate in November of 1998 was 7000 to 8000 BOPD with a GOR of approximately 800 scf/stb. In January of 1999, the well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. Gas Coning Production from the E-100 well is affected by gas coning. E-100 is a deviated well with an inclination of 46 degrees across the Kuparuk. The well is completed with a standoff of 42 feet tvd from the GOC. During the first 10 days of production, the GOR in the E-loo well increased to 2000 scf/stb. The production rate was restricted to mitigate coning. The cement bond log in this well is interpreted to show good cement quality; and the coning interpretation was confirmed by production logging. Subsequent inspection of the E-I01 core confirmed that intra-formation cementation in the upper Kuparuk would act as a baffle but not a barrier to vertical flow. With slightly more than 50% of the oil column overlain by the gas cap, coning can be a reservoir mechanism in the Midnight Sun Pool. Gas Under-Running The Midnight Sun reservoir is a thin reservoir with a structural dip of less than 2 degrees. The low structural relief results in a gas cap that overlays more than 50% of the areal extent of the oil column. Reservoir model results, calibrated to field performance, suggest that gas under-running, which is movement of gas below a barrier, will impact early field performance and is a mechanism to address in depletion planning. The GOR at well E-101 is currently 5000 scf/stb and increasing consistent with predictions. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. Page 8 of 41 I I I I I I I I I I I I I I I I I I I '\ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 DEVELOPMENT PLANS A reservoir model of the Midnight Sun Pool was constructed to evaluate development options, investigate reservoir management practices, and generate rate profiles for facility design. This section of the application describes the reservoir model, modeling results and the development plans. Reservoir Model Construction A fine scale three-dimensional geologic model of the Midnight Sun Pool was constructed based on detailed stratigraphic and structural interpretation. This model provided the bulk. reservoir volume and distribution of porosity and permeability used in the construction of the Midnight Sun reservoir model. The reservoir model is a three-dimensional, three-phase, black oil finite difference flow simulation model. The model area encompasses the graben fault block defining the Midnight Sun Pool. Areal gridding is 250 feet by 250 feet (1.43 acre cells). The vertical gridding is defined by 15 model layers with nominal thicknesses of 4 to 8 feet. Exhibit 11-3 shows average physical properties for each model layer. Faults and juxtaposition are honored through corner point geometry and non-local grid connections. Water saturation in the reservoir model was established by capillary pressure equilibrium. There is no aquifer in the reservoir model. Capillary pressure measurements suggest that the effective OWC is below the structural limit of the reservoir. The reservoir pressure was set to 4045 psia at the GOC of 8010 ft. tvdss, based on the RFf data. Exhibit 11-4 shows the comparison of model predictions and field performance. For the history match, oil rate is specified and reservoir pressure and well GOR are predicted. A history match of reservoir pressure was achieved with no modification to the gas cap volume in the reservoir model. The GOR history match reflects accurate modeling of both the coning (E-I00) and under- running (E-I0 1) reservoir mechanisms. The downstructure pore volume was increased to reflect under-run timing at well E-I0l. Page 9 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Model Results Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) up structure gas injection, and 3) waterflood. Primarv Recoverv Primary recovery was evaluated with E-101 well as the single downstructure producer. The primary recovery mechanism was a combination of gas cap expansion and solution gas drive. The gas cap at Midnight Sun contains approximately 40 percent of the total reservoir hydrocarbon pore volume. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP. Exhibit 11-5 shows production and recovery profiles for primary depletion. The performance is attributed to depletion of the gas cap and associated reduction in reservoir energy. The model shows gas under-running and high GOR production at Well E-101. The reservoir pressure was depleted at the end of the model run and the majority of the original gas cap volume had been produced. Upstrncture Gas Injection Up structure gas injection was evaluated with a horizontal injection well installed in the Midnight Sun gas cap. Reservoir management for this case assumed that injection would be sufficient to increase reservoir pressure back to the original condition and then maintain a voidage replacement ratio (VRR) of 1.0. The peak injection requirement for this case was 40 MMscfd. Model results indicate that up structure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI). Recovery of 27% was observed with 2.0 HCPVI. Exhibit 11-6 shows production and recovery profiles for up structure gas injection. Up structure gas injection results in gas under-running the top Kuparuk Formation and then coning into the perforations at the downstructure producer. As a result of these mechanisms, the vertical sweep efficiency for up structure gas injection is poor with correspondingly low recovery in the lower Kuparuk Formation. Waterflood Several waterflood development options were studied using the Midnight Sun reservoir model including up structure, downstructure, and midfield water injection. Both the Page 10 of 41 Midnight Sun Pool Rules and Area Injection Application May 3, 2000 I I I I I I I I I I I I I I I I up structure and midfield options involve water injection at or near the original gas cap. All waterflood options result in some degree of resaturation of the gas cap by oil in the midfield area. Case studies of successful application of this type of waterflood process are documented in the literature. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-I00 well to injection service. Initial production was from the E-I0 1 well. An up structure horizontal production well is completed 2,000 to 4,000 feet east of the western limit of the light oil column. This well was managed in the reservoir model to limit gas coning. The midfield waterflood shows improved waterflood response over the up structure and downstructure injection options, as evidenced by lower peak GOR and faster pressure response. Waterflood fill-up is achieved within two years of waterflood start-up. The improved response is attributed to closer injector / producer spacing and greater distance of the key production well from the gas cap. The midfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. Cumulative gas production is lower relative to the up structure injection case. Exhibit II- 8 shows production and recovery profiles for midfield water injection. The up structure configuration included a new horizontal injection well towards the western limit of the light oil column. The configuration was envisioned as a means of isolating the gas cap while waterflooding the midfield and downstructure areas. The primary downstructure producer would be well E-I0 1, although the E-I00 well was also produced for a limited time. Model results for up structure water injection indicate that the western limit of the gas cap can be isolated, and classic waterflood fill-up and response are achieved within three years of watertl.ood start-up. The up structure water injection case achieves an estimated 39% recovery at 0.7 HCPVI, although production response to waterflood is slower and gas production is greater relative to the midfield case. The downstructure configuration involves conversion of Well E-I0l to injection service. Production from Well E-I00 would be resumed and rate would initially be restricted to mitigate Page 11 of 41 I I I I I I I I I I I I I I I I I I I ~' Midnight Sun Pool Rules and Area Injection Application May 3, 2000 coning. In the downstructure waterflood configuration, an up structure horizontal production well is drilled to recover upstructure reserves. Waterflood performance for downstructure injection is less attractive than the other waterflood configurations. In this configuration, gas coning and under-running at Well E-loo require restricted field rate and continue to be a production issue for both production wells. The downstructure water injection case achieves an estimated 31 % recovery at 0.56 HCPVI with a delayed production profile relative to the up structure and midfield alternatives. Enhanced Oil Recovery (EOR) Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated. Due to the technical complexities, reservoir uncertainty, and costs involved, improved reservoir description and additional field performance data are necessary before these options may be fully evaluated. Development Plans Based on reservoir model studies, the recommended development plan is implementation of a midfield waterflood for the Midnight Sun Pool. This plan provides the most favorable production profile, while minimizing cumulative gas production and maximizing ultimate recovery. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20- 25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. Watert100d Sensitivity Studies Reservoir model sensitivity studies were conducted. in support of development planning. Model runs were conducted to optimize well placement and completion design. Sensitivities to key model assumptions, including relative permeability, vertical permeability, and oil viscosity were evaluated. None of these assumptions were found to significantly alter development plans. Other sensitivity studies included the effect of continued production prior to waterflood startup. Earlier watertlood startup mitigates reservoir pressure decline and reduces peak GOR response prior to watertlood fill-up. However, no recovery impact was identified with a waterflood start- up during third quarter 2000, assuming continued production of 5,000 BOPD until start up. In Page 12 of 41 I I I I I I I, I I I I I I I I I I I I i Midnight Sun Pool Rules and Area Injection Application ~' May 3, 2000 the reservoir model, reservoir pressure declined to 3300 psi, and GOR peaked at 8000 SCF/STB. Well Spacing The planned development well program includes the addition of one up structure horizontal production well to complete a three well development of the Midnight Sun Poo1. The development will form an irregular pattern due to the constraints of development within a small fault block. This well spacing is nonrinally 280 acres. Closer well spacing does not appear to be justified due to the thin oil column; however, infill drilling and/or peripheral drilling along the eastern margin of the field will be evaluated as field development continues. To allow for flexibility to respond to these conditions, a minimum well spacing of 80 acres is requested. RESERVOIR MANAGEMENT STRATEGY Gas cap expansion will provide initial pressure support prior to waterflood start-up. Following waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. In the planned waterflood configuration, oil flux into the gas cap is anticipated in the midfield area due to low structural relief. Reservoir surveillance and voidage management, however, should minimize oil flux to the west of the up structure horizontal producer. The objective of the Midnight Sun reservoir management strategy is to manage reservoir development and depletion to 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 historical performance. New well results and additional reservoir performance data will increase knowledge and improve predictive capabilities resulting in adjustments to the initial strategy. The reservoir management strategy for the Midnight Sun Pool will continue to be evaluated throughout field life. Page 13 of 41 I I I I I I I I I I I I I II I· I I' .1 I :( Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Reservoir Perlonnance Conclusions Reservoir model results support implementation of a waterflood in the Midnight Sun Pool. An initial three well development program is contemplated, with midfield water injection at Well E- 100, and the addition of one up structure horizontal producer. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. Following initiation of waterflood, a peak production rate of 8-10,000 BOPD is expected. We request that the Operator be allowed to determine the field off-take rate based upon sound reservoir management practices. Page 14 of 41 ~ Midnight Sun Pool Rules and Area Injection Application {' May 3, 2000 III. Facilities I I I I I, I' I I I I: I \ I I I I I I GENERAL OVERVIEW Midnight Sun wells will be drilled from the E- Pad drill site. Surface facilities include existing IP A drill sites, pipelines and processing facilities to produce Midnight Sun Reservoir fluids. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E- Pad and then transported to Gathering Center 1 (GC1) for treatment and shipment to Pump Station No. 1 (PS-l). Midnight Sun will make use of existing IPA infrastructure. This mininrizes environmental impacts and reduces costs to help maximize recovery. Use of the GC 1 production facility includes 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 24" low-pressure common line from E-pad to GC1, 16" and 6" high-pressure common lines from E-pad to GC1, oil sales line from GCl to PS-l and the power distribution and generation facilities. Exhibit III -1 is an area map showing locations of the facilities that will be used for Midnight Sun development. Drill Sites, Pads, and Roads Use of the E- Pad drill site for the Midnight Sun wells has been selected to (1) eliminate new gravel placement, (2) mininrize well stepout to within currently available drilling technology while reaching the extent of the reservoir, and (3) maximize the use of existing facilities. Wells will be drilled between existing IP A wells, eliminating the need to expand the E- Pad. A schematic of the drill site layout is shown in Exhibit 111-2. No new pipelines will be required for development of the Midnight Sun reservoir. Midnight Sun production will be routed to GCl via existing E-Pad high pressure and low-pressure commonlines. No new roads or roadwork will be required. Page 15 of 41 ( Midnight Sun Pool Rules and Area Injection Application :{ May 3, 2000 I I I I I I I I I I I I', I I I I I I Drill Site Facilities and Operations Two existing E-Pad production manifold slots and well lines will be used for the Midnight Sun wells. Water for waterflood operations will be obtained from source water wells equipped with electrical submersible pumps (ESPs) to deliver water to the injection well at a rate of 10,000 bpd from each source water well at minimum pressure of 2100 psig. The source water injection system is illustrated in Exhibit 111-3. Future gas lift gas will be obtained from an IPA E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. Power for new Midnight Sun drill site equipment will be provided by installing a new 15 kv power line from GC 1 to the Midnight Sun facilities at E- Pad. All well control at the drill sites will be performed manually by a drill site operator with the exception of the well safety shut in systems (which are automatic) and the drill site emergency shutdown system (which can be triggered manually or automatically). Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. The skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IP A fluids at E- Pad for transport to GCl. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IP A. Production allocation is addressed in Section V. Data gathering at the drill site will be both a manual and automatic function. The data gathering system (SCADA) will be expanded to accommodate the Midnight Sun wells and drill site equipment. The SCADA will continuously monitor the flowing status, pressures, and temperature of the producing wells at the drill sites. These data will be under the drill site operator's supervision through his monitoring station. Midnight Sun production metering will continuously Page 16 of 41 ~ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 I I I I I I I I I I I I I I I I I I monitor the pressures, temperatures, and flow of the liquid and gas streams. The rate of production from each well will be regulated by manually adjusted chokes. The flow from the wells would be routed to the production metering skid and then to GC 1 for processing. Production Center No modifications to the GC1 production center will be required to process the Midnight Sun production. GC1 was built to process a nominal oil rate of 400 MBOPD, gas rate of 320 MMSCFPD (modifications have increased this to 2,600 MMSCFPD) and a produced water rate of 40 MBWPD (modifications have increased this to 85 MBWPD). Production, including that from the Midnight Sun Reservoir, is not expected to exceed existing GC1 capacity. RECEIVED ., :" ':"' 0 4 2000 Alaska Oil & Gas Cons. Commission Anchorage Page 17 of 41 I I I I I I I I I I I I .' I I I I I I ,¡' { Midnight Sun Pool Rules and Area Injection Application { May 3, 2000 IV . Well Operations DRn...LING AND WELL DESIGN Two wells have been drilled in the Midnight Sun Pool, E-I00 and E-I01. E-I01 is currently producing with plans to convert E-loo to an injector. Exhibit IV -1 shows the schematic of the E- 100 well. The Midnight Sun depletion plan calls for drilling three additional wells: two shallow source water wells and one horizontal up structure producer, each drilled from E- Pad. Midnight Sun wells would be directionally drilled from E- 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 Commission requirements will be installed on the conductor. Surface hole would be drilled no deeper than 5,000 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 Midnight Sun wells. Cementing and casing requirements similar to other North Slope fields will be adopted for Midnight Sun. The casing head and a 5,000-psi blowout-preventer stack will be installed onto the surface casing and tested consistent with Commission requirements. 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. Intermediate casings and production liners will be used to achieve specific completion objectives or to provide sufficient contingency in mechanically challeng~g wells such as high departure wells. To date, H2S has not been detected in any Midnight Sun wells. However, with planned waterflood operations, there is some potential of generating small amounts of H2S over the life of the field. Page 18 of 41 I ~ Midnight Sun Pool Rules and Area Injection Application ~, May 3, 2000 I I I I I I I I I I I I I I I .' I Safe drilling practices, to account for the effects of H2S gas on both people and equipment 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. The nature of the wells to be drilled requires the use of E-75, 0-105, or S-135 grade drillpipe. These materials are susceptible to sulfide stress cracking but can be used safely under the controlled conditions recommended in Section 8, "Drill Stem Corrosion and Sulfide Stress Cracking," of API RP 70, "Drill Stem Design and Operating Limits" which will be used as applicable. WELL DESIGN AND COMPLETIONS Three additional wells are planned for Midnight Sun, two water supply wells and one horizontal producer. The water supply wells would be drilled into the Tertiary interval and completed with a single casing string and downhole electric submersible pumps (ESPs). Open hole gravel packs would be used in the water supply wells to maximize productivity and prevent sand production. Tubing sizes will vary from 3-112 to 5-112 inches in Midnight Sun wells. The up structure horizontal producer is planned with a measured depth of over 14,000 ft. and would be completed in the Kuparuk Formation. This departure would necessitate top-setting the Kuparuk. In general, the production casing will be sized to accommodate the desired tubing size in the Midnight Sun wells. The following table indicates the casing and tubing sizes utilized in the proposed well designs for the Midnight Sun wells. Surface Casing Inter I Prod Casing Production Liner Production Tubing Water Supply 9-5/8H N/A N/A 4-112" Horizontal 10-314" or 9-5/8" 7 -5/8" or 7" 4-1/2" or 3-1/2" 4-1/2" or 3-1/2" Page 19 of 41 I it Midnight Sun Pool Rules and Area Injection Application ( May 3, 2000 I I! I I I I I I I I I I I I I I I Plans are to run L-80 tubing and casing in these wells. All tubing jewelry will be completed with 9-Cr/1Moly, which is compatible with both L-80 and 13-Cr. All proposed wells call for completion in a single zone, with a single string and a single packer. As shown in the schematic, the wells have gas lift mandrels with dummy valves to provide flexibility for artificial lift if needed to enhance production rates. Sufficient mandrels will be run to provide flexibility for changing well production volumes, gas lift supply pressure, and changes in WORe SUBSURFACE SAFETY VALVES Subsurface safety valves do not appear to be necessary in the Midnight Sun wells according to statewide regulations (20 AAC 25.265). Existing completions are equipped with SSSV nipples. The up structure producer would be completed in a similar manner. SURFACE SAFETY V ALVES 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 the standard PBU Operator practices. DRILLING FLUIDS In order to minimize skin damage from drilling and to maintain shale stability, water-based KCI mud will be used to drill through the Midnight Sun Pool and nearby shales while low solids, non- dispersed fluids will be used for the upper sections of the well. STIMULA TION METHODS Stimulation to enhance productivity or injection capability is not currently planned for Midnight Sun wells. Formation damage associated with drilling and completion activity appears to be Page 20 of 41 ~. Midnight Sun Pool Rules and Area Injection Application ¡f May 3, 2000 minor or insignificant. The use of stimulation in the medium to high permeability rock may be evaluated at a later date. I I I II I I I I I I I I I I I I RESERVOIR SURVEILLANCE PROGRAM Midnight Sun data will continue to be collected to monitor reservoir performance and, define reservoir properties. Reservoir Pressure Measurements An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. This 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. The reservoir pressures will be reported at the common datum elevation of 8,050 ft. tvdss. Surveillance Logs Surveillance logs, which may include flowmeters, temperature logs, or other industry proven downhole diagnostic tools, will be periodically run to help determine reservoir performance (e.g., aoe monitoring and injection profile evaluation). Page 21 of 41 l Midnight Sun Pool Rules and Area Injection Application { May 3, 2000 v. Production Allocation I I I I:, I I I I I I I I I I I I Initially, a combination of well tests and wellhead pressure trends will continue to be used to allocate production. Under this methodology, the production from an individual well is first calculated from the average daily wellhead pressure using the deliverability equation. During periods of rising GOR and changing tubing hydraulics, the deliverability equation may not accurately reflect the production as measured by well tests. During such periods, the daily well production is detefllÙned by linear interpolation between well test points. A minimum of two well tests per month, as well as lab-measured water cuts and zero-rate tests, are performed on Midnight Sun wells to ensure allocation accuracy. Summing the calculated daily production volume for all producing wells provides an estimate of the Midnight Sun daily field production. A fixed allocation factor 'of 1.0 is used for Midnight Sun. The long-term metering plan for Midnight Sun is to use continuous production metering. The metering skid described in the Facilities section of this application will be used to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IPA production at E-Pad. Each wellhead will have a continuous two-phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. We request Commission approval under 20 AAC 25.215(a) that the Midnight Sun metering is an acceptable method. An allocation factor of 1.0 would continue to be used with the continuous meter. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate we1ll1ead allocation factors. Consistent with existing reporting, no NGLs will be allocated to Midnight Sun. Page 22 of 41 ~~ '~. Midnight Sun Pool Rules and Area Injection Application May 3/ 2000 VI. Area Injection Operations I I I· I I I I I I I I I I I I I. I This application, prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders), requests authorization for water injection to enhance recovery from the Midnight Sun Oil Pool. This section addresses the specific requirements of 20 AAC 25.402(c). PLAT OF PROJECT AREA 20 AAC 25.402(c)(1) Exhibit 1-2 shows the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Midnight Sun Oil Pool as of April 1, 2000. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. OPERATORS/SURFACE OWNERS 20 AAC 25.402(c)(2) and 20 AAC 25.402(c)(3) PIDLLIPS Alaska, Inc. is the designated operator of the Midnight Sun Participating Area. Surface Owners within a one-quarter mile radius and inclusive of the Midnight Sun Participating Area are as followings: State of Alaska Department of Natural Resources Attn: Ken Boyd P.O. Box 107034 Anchorage, AK 99510 Pursuant to 20 AAC 25.402(c)(3), Exhibit VI-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 Midnight Page 23 of 41 I I I I I I I I I I I I I I I I .' ( Midnight Sun Pool Rules and Ar~a Injection Application May 3, 2000 Sun Participated Area have been provided a copy of this application for injection. DESCRIPTION OF OPERATION 20 AAC 25.402(c)(4) Development plans for the Midnight Sun Oil Pool are described in Section II of this application. Drillsite facilities and operations are described in Section III. The source water wells will be permitted and constructed in accordance with 20 AAC 25.005. GEOLOGIC INFORMATION 20 AAC 25.402(c)(6) The Geology of the Midnight Sun Oil Pool are described in Section I of this application. INJECTION WELL CASING INFORMATION 20 AAC 25.402(c)(8) The B-1 00 Well will be converted to injection service for the Midnight Sun Oil Pool Enhanced Recovery Project. The casing program for this well was permitted and completed in accordance with 20 AAC 25.030. Exhibit IV-l details the completion for the E-I00 Well. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. Conversion of the E-I00 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 HzS in accordance with 20 AAC 25.065. Page 24 of 41 ( Midnight Sun Pool Rules and Area Injection Application '~ May 3, 2000 I I I I I I I I I I I I I I I I I INJECTION FLUIDS 20 AAC 25.402(c)(9) Type of Fluid/Source Primary Source - The Midnight Sun Enhanced Recovery Project will utilize water produced from the Tertiary Sagavanirktok formation, as shown in Exhibit VI-2, as an initial and primary water source. Alternate Source - Produced water from GC 1 or produced water separated directly from Midnight Sun production at E- Pad have been identified as potential alternate water source options. Composition Primary Source - A water sample from the Tertiary water source interval has not been obtained. However, it is anticipated the water will be of similar composition as water produced from the DS 15-6 Well in the Cretaceous interval. The DS 15-6 Well water composition is shown in Exhibits VI-3. Alternate Source - The composition of produced water from GC1 is shown in Exhibits VI-4. The composition of Midnight Sun produced water will be a mixture of connate water and source injection water. No oil-water contact has been identified in the Midnight Sun Oil Pool and no significant connate water production has occurred or is anticipated. In order to conduct geochemical modeling, the Midnight Sun Oil Pool connate water composition is assumed to be similar to samples from the offset Pt. McIntyre Oil Pool (refer to Exhibit 1-3 in the "Application for Modification to Area Injection Order No.4", dated April 5, 1993). Maximum Injected Rate Maximum water injection requirements at Midnight Sun Oil Pool are estimated at 25,000 BWPD. Compatibility with Formation and Confining Zones Core analyses and geochemical modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. Analysis of the E-101 core indicates low clay content (less than Page 25 of 41 I I I I I I I I I I I I I I I I I I I II Midnight Sun Pool Rules and Area Injection Application May 3, 2000 5% by volume), primarily in the form of kaolinite and illite. No fines migration problems are anticipated. Geochemical modeling results indicate that a combination of Tertiary water and connate water is likely form calcium carbonate and barium sulfate scale in the production wells and downstream production equipment. Similar scaling problems are anticipated for the alternate source water options. Scale precipitation will be controlled using standard oil field scale inhibition methods. INJECTION PRESSURES 20 AAC 25.402(c)(10) The expected average surface water injection pressure for the project is 2250 psig. The estimated maximum surface injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Projects is 2750 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 Midnight Sun Oil Pool Enhanced Recovery Project well(s) will not initiate or propagate fractures through the confuring 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 Page 26 of 41 I I I I I I I I I I I I I I I I I I I { Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Formation. Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Enhanced Recovery Water injection operations at the Midnight Sun 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 Midnight Sun 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 data for the HRZ and Kalubik. intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. No tests have been conducted to determine the formation breakdown pressure at the Midnight Sun Oil Pool; however, data from offset fields suggest that a fracture gradient of between 0.6 and 0.7 psi/ft can be expected in the Kuparuk River Formation at initial reservoir conditions. 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. The reservoir temperature for the Midnight Sun Oil Pool is approximately 160OP, and the expected surface water injection temperature is 60 - 80OP. The cold water injection is expected to reduce the fracture gradient by .03 to .05 psi/ft. Page 27 of 41 I I I I I I I I I I I I I I I I I I I ,i' ~. Midnight Sun Pool Rules and Area Injection Application May 3, 2000 HYDROCARBON RECOVERY 20 AAC 25.402(c)(14) The Midnight Sun Oil Pool is estimated to have an original oil in place of 40 to 60 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. Page 28 of 41 I I I I I I I I I I I I I I I I I I I i( Midnight Sun Pool Rules and Area Injection Application i May 3, 2000 VII. Pool Rules Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Pool Rules for the Midnight Sun Oil Pool. Geology 1. The Midnight Sun Pool is located north of the Prudhoe bounding fault system and southwest of the Pt. McIntyre Pool. The reservoir interval is the Kuparuk River Formation. 2. The Midnight Sun Pool was discovered in 1997 during the drilling of the Sambuca #1 (E-100) well. The well encountered 100 feet of gross hydrocarbon column, with 36 feet of gas above the oil column. 3. In the E-100 well, the top of Kuparuk Formation occurs at 7,974 ft. tvdss (11,662 ft. md) and the base occurs at 8,074 ft. tvdss (11,805 ft. md). 4. Well E-101 (Midnight Sun #1) was drilled as a downstructure delineation well in the Midnight Sun Pool. The well encountered 84 feet of gross hydrocarbon column all below the ODe identified in the B-100 well. 5. Lithology is dominantly sandstone with lesser amounts of siltstone and sandy mudstone. The Kuparuk Formation can be divided into upper and lower units. In the lower reservoir unit, which is typically about 40 feet thick, the lithology changes abruptly to porous, quartz-rich sandstone. Grain size is typically very fine to fine-grained and is well sorted. The lithology of the upper unit is variable including interbedded sandstone with minor amounts of muddy siltstone. The thickness of this interval is variable and ranges from 0 to 70 feet. This interval contains glauconite and siderite and is more prone to reductions in porosity and permeability due to cementation and compaction. 6. The Midnight Sun Pool is bounded to the west by the Prudhoe Mid-Field fault, to the south by the Prudhoe bounding fault system, to the north by the Sambuca fault, and to the east by the North Prudhoe structural high. 7. The top of the Kuparuk horizon reaches a structural high to the southwest at 7,780 ft. tvdss against the Prudhoe bounding fault. The Kuparuk Formation dips eastward to a zero edge against the North Prudhoe high at approximately 8,100 ft. tvdss. The structural dip is less than 2 degrees. 8. The Midnight Sun accumulation is a combination structura1lstratigraphic trap, with isolation assisted by neighboring structural highs that are fault controlled. The controls on Kuparuk Page 29 of 41 I I I I I I I I I I I I I I I I I I I ~' Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Formation thickness are fault movement and erosional truncation. 9. The Midnight Sun Pool gas-oil contact (GOC) is interpreted to be at a depth of 8,010 ft. tvdss, based on Repeat Formation Tester (RFf) data. 10. No oil-water contact (OWC) was identified in either of the Midnight Sun wells. 11. Heavy oil was encountered at 8,107 ft. tvdss in the E-I0l well. Conventional core from the E-I0l well contained heavy oil in the lower Kuparuk section below 8,107 ft. tvdss. The areal extent of the heavy oil is uncertain. Reservoir Description and Development Planning 1. Mean porosity for the upper Kuparuk Formation is 20.7%, based on E-I01 core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean porosity is 27.3%. 2. Mean permeability for the upper Kuparuk Formation is 200 md, based on E-I0 1 core data. In the lower Kuparuk Formation, excluding the non- reservoir basal interval, the mean permeability is 760 md. 3. The net-to-gross ratio for the upper Kuparuk Formation ranges from 0.25 - 0.72. The lower Kuparuk. Formation has negligible glauconite and siderite content and exhibits a net-to-gross ratio of approximately 1.0. The non-reservoir basal interval in the lower Kuparuk Formation section is heavily cemented, with a net-to-gross ratio of 0.0. 4. Mean water saturation for the upper Kuparuk Formation is 26.4%, based on E-I0l core data. In the lower Kuparuk Formation, excluding the non-reservoir basal interval, the mean water saturation is 12.6%. 5. Based on RFr data, the initial reservoir pressure is estimated at 4058 psia at the reservoir datum of 8050 ft. tvdss. The reservoir temperature is approximately 160 degrees Fahrenheit. 6. Reservoir fluid PVT studies were conducted on a recombined surface sample obtained from the E-I0l well. The API gravity of the PVT sample was 25.5 degrees with a solution gas-oil- ratio (GOR) of717 scf/stb, a formation volume factor of 1.33 RVB/STB, and an oil viscosity of 1.68 centipoise at the bubble point pressure. 7. The Midnight Sun Pool contains an estimated Original Oil In Place (OOIP) of 40 to 60 MMSTB, and total gas in place of 100 to 130 BSCF. The free gas volume associated with the gas cap is 60 to 80 BSCF. 8. Production of the Midnight Sun Pool commenced in October of 1998. Early production from the E-l 00 Well was restricted to mitigate gas coning, and is currently shut in to limit reservoir voidage. Page 30 of 41 I Midnight Sun Pool Rules and Area Injection Application May 3, 2000 I I I I I I I I I I I I I I I I I 9. Production from well E-101 demonstrates gas under-running. In January of 1999, the E-101 well was restricted to 5000 BOPD to conserve reservoir energy while completing reservoir surveillance and field development studies. 10. A reservoir model of the Midnight Sun Pool was constructed and history matched to evaluate development options, and reservoir management practices. 11. Three development options were evaluated for the Midnight Sun Pool: 1) primary depletion, 2) up structure gas injection, and 3) waterflood. 12. Model results indicate that primary depletion would achieve an estimated 14% recovery of the OOIP 13. Model results indicate that up structure gas injection would achieve an estimated 20% recovery of the OOIP after 1.0 hydrocarbon pore volume injection (HCPVI) and 27% after 2.0 HCPVI. The vertical sweep efficiency for up structure gas injection is poor, showing low recovery in the lower Kuparuk unit. 14. Several waterflood development options were studied using the Midnight Sun reservoir model including up structure, downstructure, and midfield water injection. The midfield configuration showed the best overall waterflood performance with greater ultimate recovery and an earlier production profile associated with improved pressure response relative to the other cases. The midfield configuration involves conversion of the E-100 well to injection service. The rrùdfield water injection case achieved an estimated 39% recovery at 0.7 HCPVI. 15. Based on reservoir model studies, the recommended development plan involves implementation of a rrùdfield waterflood for the Midnight Sun Pool. The planned development well program includes the addition of one up structure horizontal production well to complete a three well development of the Midnight Sun Pool. 16. The development plan results in a nominal spacing of 280 acres for the three well development, however the operator has requested a minimum well spacing of 80 acres. 17. Gas cap expansion will provide initial pressure support prior to waterflood start-up. 18. Water injection is expected to commence in the third quarter of 2000, with design injection rates of 20-25,000 BWPD. A peak production rate of 8-10,000 BOPD is expected prior to waterflood breakthrough. 19. Following waterflood start-up, the VRR target will exceed 1.0 to suppress gas production and restore reservoir pressure. A balanced VRR will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. Page 31 of 41 I I I I I I I I I I I I I I I I I I I ( Midnight Sun Pool Rules and Area Injection Application I' II May 3, 2000 20. Model results indicate that oil flux into the gas cap will occur as a result of the low structural relief. Reservoir surveillance and void age management will mitigate oil flux to the west of the up structure horizontal producer. 21. Preliminary analysis indicates there may be potential for enriched gas injection at Midnight Sun; however, no EOR project evaluations have been initiated Facilities 1. Midnight Sun wells will be drilled from the E-Pad drill site and make use of existing IPA infrastructure. 2. Midnight Sun fluids will be commingled with Initial Participating Area (IP A) fluids on the surface at E-Pad and then transported to Gathering Center 1 (GC1) for treatment and shipment to Pump Station No.1 (PS-l). 3. Water for waterflood operations will be obtained from two source water wells equipped with electrical submersible pumps 4. Future gas lift gas will be obtained from an IPA E-pad well. Gas removed from this well for raw gas lift will be metered prior to the gas being introduced into any Midnight Sun well. This IP A gas will be returned to the IP A. 5. Initially, production will be allocated based upon well tests as previously approved by the Commission. After a new metering skid is installed in the third or fourth quarter 2000, Midnight Sun production will be continuously metered prior to combining with IP A production. 6. The continuous metering skid will consist of a two-phase separator, with liquids measured by a mass meter and gas production measured by conventional orifice plate methods. The Midnight Sun oil gravity will be used to calculate the oil and water volumes based on the liquid mass measurement. After metering, the gas and liquid streams will be re-combined and commingled with IP A fluids at E- Pad for transport to GC 1. The data obtained from the metering skid will provide the basis for allocating production between Midnight Sun and the IPA. Well Operations 1. Additional Midnight Sun Pool development wells will use drilling procedures, well design, and casing and cementing programs consistent with those currently used in other North Slope fields. 2. All proposed wells call for completion in a single zone, with a single tubing string and a single packer Page 32 of 41 I I I I I I I I I I I I I I I I I I I ~ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 3. Sub-Surface Safety Valves (SSSV) are not installed in existing Midnight Sun, and are not planned for additional wells, however, nipples are installed to allow flexibility to install wireline retrievable SSSV s. 4. Surface safety valves are included in the wellhead equipment of existing Midnight Sun Pool wells. Testing of SSVs will be in accordance with the standard PBU Operator practices. 5. Stimulation to enhance productivity or injection capability is not currently planned for Midnight Sun wells. 6. An initial static reservoir pressure will be measured in each new well prior to production. Additionally, a minimum of one pressure survey will be taken annually for the Midnight Sun Pool. A pressure datum elevation of 8,050 ft. tvdss is recommended. Production Allocation 1. Initially, a combination of well tests using the E- Pad facilities and wellhead pressure trends will continue to be used to allocate production. The daily well production is determined by linear interpolation between well test points. 2. A continuous production metering will be installed to continuously meter the entire Midnight Sun production stream through a compact two-phase separator before it is commingled with IP A production at E- Pad. 3. Each wellhead will have a continuous two-phase meter to monitor fluid and gas production, with monthly shakeouts to ascertain water cut. An allocation factor of 1.0 would continue to be used with the continuous meter. 4. The Midnight Sun Pool will have a set allocation factor of 1.0, with production allocated back to individual wells using the continuous two-phase metering data to calculate wellhead allocation factors. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. Commercially exploitable hydrocarbons are present in the Midnight Sun Pool, contained within Kuparuk River Formation. 2. Pool rules for the development of the Midnight Sun reservoir are appropriate at this time. Page 33 of 41 I I I I I I I I I I I I I I I I I I I ~ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 3. An integration of interests for the area contemplated for development by the operator exists between the working interest owners and royalty owners. 4. The vertical limits of the Midnight Sun reservoir may be defined in the E-lOO well which appears to be a typical and representative well. 5. The low structural relief at the Midnight Sun reservoir limits the effectiveness of gas cap expansion or gas injection as a recovery mechanism. 6. Waterflood operations are planned and appear to achieve the greatest ultimate recovery of oil 7. Other than establishing setting depths, the operator is not requesting variance from statewide casing and cementing requirements. 8. The E- Pad drillsite is an onshore location 9. Subsurface safety valves are not required by statewide regulations 10. Surface comnùDgling of Midnight Sun production with IP A and other Prudhoe satellite production will increase ultimate recovery, will not cause waste nor jeopardize correlative rights. 11. The Midnight Sun continuous metering plan is an acceptable method of allocating produced fluids back to the Midnight Sun Pool for revenue and reservoir management purposes. 12. Appropriate reservoir surveillance data will be obtained to complete development and conduct appropriate reservoir management. 13. The operator has demonstrated that primary depletion, supported by gas cap expansion, does not adversely impact ultimate recovery as long as waterflood operations commence before the reservoir pressure drops below 3300 psi at the reservoir datum. 14. Exception to the gas-oil-ratio limit of20 AAC 25.240(b), is appropriate at this time. PROPOSED RULES PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following Pool Rules for the Midnight Sun Oil Pool: Subject to the rules below and statewide requirements, production from the Midnight Sun reservoir 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. Page 34 of 41 I I I I I I I I I I I I I I I I I I I Midnight Sun Pool Rules and Area Injection Application May 3, 2000 In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Midnight Sun Pool. Rule 1: Field and Pool Name and Classification The field is the Prudhoe Bay Field and the pool is the Midnight Sun Pool. The Midnight Sun Pool is classified as an Oil Pool. Rule 2: Pool Definition TI2N-RI3E: See 25, SI/2; Sec 36, N1I2, SE1I4, E1I2 of SW1I4 TI2N-RI4E: See 29, ALL; See 30, S1I2, S1I2 ofNE1I4, S1I2 ofNW1I4; Sec 31, N1I2, SW1I4, N1I2 of SE1I4; See 32, NW1I4 TI2N-RI4E: Sec 28, W1I2, W1I2 of NE1I4, W1I2 of SE1I4 The Midnight Sun Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 11,662 and 11,805 feet in the E-I00 well. Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer than 300 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 at six-month intervals. Rule 5: Common Production Facilities and Surface Commingling (a) Prior to installation of a continuous metering skid, producing Midnight Sun wells will be tested a minimum of 2 times per month and production will be allocated by interpolating between well test results. (b) After installation of the continuous metering skid, the requirements of20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Pool as a whole, and then allocating that production to each well daily. (c) The allocated production for the Midnight Sun Pool will not be adjusted in conjunction with the ¡PA allocation factors (Le. the Midnight Sun allocation factor will be 1.0). (d) The operator shall submit monthly reports containing daily production metering and daily well allocations. Page 35 of 41 I I I I I I I I I I I I I I I I I I I ~ Midnight Sun Pool Rules and Area Injection Application May 3, 2000 Rule 6: Reservoir Pressure Monitoring (a) A minimum of one bottom-hole pressure survey will be taken annually for the Midnight Sun Pool. (b) The reservoir pressure datum will be 8,050 feet true vertical depth subsea. (c) Pressure surveys may 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. (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 Midnight Sun 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 connnence before reservoir pressure drops below 3300 psi at the datum or within 2 years 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 any other special monitoring. 4. Future development plan. The report will be submitted to the Comnússion by the end of first quarter of each year. Rule 10: Administrative Action Upon proper application, the Comnússion 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. Page 36 of 41 I I I I I I I I I I I I I I I I I I I ~ Midnight Sun Pool Rules and Area Injection Application { May 3, 2000 VIII. Area Injection Application Proposed Findings, Conclusions, and Rules PROPOSED FINDINGS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following findings in establishing an Area Injection Order for the Midnight Sun Oil Pool. 1. The reservoir interval containing the Midnight Sun Oil Pool is the Kuparuk River Formation. 2. Production from the Midnight Sun Oil Pool commenced in October of 1998. There are currently two wells in the Midnight Sun Oil Pool. The location and mechanical configuration of these wells are identified in the application. There are currently no injection wells in the Midnight Sun Oil Pool. 3. Initial enhanced recovery plans for the Midnight Sun Oil Pool call for conversion of one well, E-100, to water injection. Water injection is expected to commence in the third quarter of 2000, with a nominal design injection rate of 20-25,000 BWPD. 4. Operators and Surface Owners within a one-quarter mile radius of the area included in the Midnight Sun Participated Area have been provided a copy of this application for injection. 5. Injection water for the enhanced recovery project will be provided by two local source water wells drilled at E-Pad and completed with Electrical Submersible Pumps (ESPs) in the Tertiary Sagavanirktok Formation. Produced water from GC1 or produced water separated directly from Midnight Sun production at E-Pad have been identified as potential alternate water source options. 6. An initial three well· development program is contemplated, with midfield water injection at the E-1oo Well, and the addition of one up structure horizontal producer. Additional injection and production wells may be considered depending on reservoir performance and ongoing technical evaluation. 7. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 15 to 25% of the estimated 40-60 MMSTB original oil in place, relative to primary depletion driven by gas cap expansion. Page 37 of 41 I I I I I I I I I I I I I I I I I I I It' Midnight Sun Pool Rules and Area Injection Application :1; '\ May 3, 2000 8. The casing program for the E-l00 Well was permitted and completed in accordance with 20 AAC 25.030. A cement bond log was recorded and indicates good cement bond across and above the Kuparuk River Formation. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. 9. Estimated maximum and average injection pressures (psig) for the Midnight Sun Oil Pool are 2250 psig and 2750 psig, respectively. 10. Following watert100d start-up, the voidage replacement by water injection will exceed offtake to suppress gas production and restore reservoir pressure. A balanced voidage replacement will be maintained once reservoir pressure is restored to a target range of 3800 - 4000 psi. 11. Core analyses and geochel1Ùcal modeling indicate no significant problems with clay swelling or compatibility with in-situ fluids. 12. Water injection operations at the Midnight Sun Oil Pool are expected to be above the Kuparuk River Formation parting pressure to enhance injectivity and improve recovery of oil. 13. The expected maximum injection pressure for the Midnight Sun Oil Pool Enhanced Recovery Project well(s) will not initiate or propagate fractures through the confining strata (Kalubik and HRZ shales), and, therefore, will not allow injection or formation fluid to enter any freshwater strata. 14. There are no freshwater strata overlying the proposed area for this enhanced recovery project. PROPOSED CONCLUSIONS PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission consider adopting the following as its conclusions: 1. The requirements of 20 AAC 25.402, and 20 AAC 25.460 have been met for the injection of water for the proposed Midnight Sun Oil Pool enhanced recovery operations. 2. Establishment of a new Area Injection Order for the Midnight Sun Oil Pool area will not cause waste nor jeopardize correlative rights, and is based on sound engineering principles. 3. No underground sources of drinking water (USDW) are known to exist in the Western Operating Area of the Prudhoe Bay Unit, including the proposed Midnight Sun Oil Pool. 4. Authorizing injection of water for enhanced recovery operations in Midnight Sun Oil Pool is Page 38 of 41 I I I I I I I I I I I I I I I I I ,I I !i Midnight Sun Pool Rules and Area Injection Application May 3, 2000 appropriate and in accordance with sound engineering principles. 5. Injection operations in the Western Operating Area of the Prudhoe Bay Unit, and the Midnight Sun Oil Pool will be conducted in permeable strata which can reasonably be expected to accept fluids at pressures less than the fracture pressure of the confining strata. 6. Specific approvals to convert or drill injection wells will be required. PROPOSED RULES PHILLIPS Alaska, Inc., in its capacity as Midnight Sun Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery in the Midnight Sun Pool and consider the following rules to govern such activity: Affected Area: TI2N-RI3E: Sec 25, S1I2; Sec 36, N1I2, SE1I4, E1I2 of SW1I4 TI2N-RI4E: Sec 29, ALL; Sec 30, SI/2, S1I2 ofNE1I4, S1I2 ofNW1I4; Sec 31, N1I2, SW1I4, N1I2 of SE1I4; Sec 32, NW1I4 TI2N-RI4E: Sec 28, W1I2, W1I2 of NE1I4, W1I2 of SE1/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Within the affected area, Class II fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata defined as those which correlate with and are common to the formation found in the E-l00 Well between the measured depths of 11,662-11,805 feet. Rule 2: Fluid Injection Wells The injection of fluids must by conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; or 2) through an existing well that has been 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 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. Page 39 of 41 I I I I: I I I I I I I I I I I I '. I I Ii Midnight Sun Pool Rules and Area Injection Application May 3, 2000 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 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 must be held for at least a 30 minute period with decline no more than or equal to 10% of test pressure. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Rule 6: Well Integrity Failure Whenever disposal rates and/or operating pressure observations 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: Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering principles, and will not result an increased risk of fluid movement into an USDW. Page 40 of 41 I I I I I I I I I I I I I I I I I I I if Midnight Sun Pool Rules and Area Injection Application May 3, 2000 IX. Exhibits Exhibit 1-1 Location Map of Midnight Sun Pool Exhibit 1-2 Midnight Sun Participating Area Exhibit 1-3 Type Log (E-IOO) - Kuparuk Interval Exhibit 1-4 Top Kuparuk Structure Map for Midnight Sun Pool Exhibit 1-5 Kuparuk Isochore Map for Midnight Sun Pool Exhibit 1-6 East-west well structural cross-section along axis of Midnight Sun Pool Exhibit 1-7 North-south well structural cross-section across Midnight Sun Pool Exhibit 1-8 Net sandstone map for Midnight Sun Pool Exhibit 1-9 Gross hydrocarbon distribution map for Midnight Sun Pool Exhibit II-I Fluid Property Summary for the Midnight Sun Pool Exhibit 11-2 Pressure- V olume- Temperature (PVT) Properties as a Function of Pressure Exhibit 11-3 Reservoir Model Layering and Average Physical Properties Exhibit 11-4 Comparison of Model Predictions and Field Performance Exhibit 11-5 Production and Recovery Profiles for Primary Depletion Exhibit 11-6 Production and Recovery Profiles for Up structure Gas Injection Exhibit 11-7 Production and Recovery Profiles for Waterflood Exhibit 111-1 Facility Location Map Exhibit ITI-2 Drill Site Schematic Exhibit ITI-3 Source Water Injection System Exhibit IV-l E-IOO Wellbore Schematic Exhibit VI-l Affidavit of Notification Exhibit VI-2 Shallow Section Type Log E-16 - Source Water Intervals Exhibit VI-3 DS 15-6 Produced Water Sample Analysis Exhibit VI-4 GC #1 Produced Water Sample Analysis Page 41 of 41 Exhibit I -I. Regional Locator Map f - ¡rr--- ~'fJ"'"'~'~'~ . -"..~'--~--: h:- :-=.~_'~, . r:\...>." .j , .. _,_~1ti.: ~.. c· ì J ¡ _.; _. 5.;::~~-r· :ç~., ~ !cy~ .. .' \:. ,9 - 0" ..- ¡L·.~:_-~.;·~,- ~~:~~::,~~ ~~ i-.i¡.~·~~., ".r -~ ~..·;!·I.W-l_ ..... 1.~~ 1~ ~ '1 I ~ì ~-i .,~ i ~j ~ ¡ J f. . .....m.-- .. "!:."".f..~ --,- - .-- I i I""' i I ....I~ r-:-ÃÃCO~~. O! ~ ~f'.R ... Lf8"~ ~ J j ~~~"7li"' 1 I I G_1nl1ad ¡ r ¡ ~..... K",I,JI( 1 ì ~~an.... ¡ _ ~, ct... ; '"'T ~. ___.._.""..___....i _, . .. ~~~~.~+t;'þfr.~ - ~"'" 1 ~..._~-t!';Io , m·:i~ ~ ~.,;:~....""l(¡ ---- L _"f:.l'¡...~ dl'~~~ I ~--200j;:!¡o 1 - - Jf::?o..~ L ~~.e::.f. I f i ::;:':~ ~"~.;:;.;~,: ,~ I~}..¡,ÿ". ')þ.-l!'q:!. 1 1 , - i ! . ! ~ i I !J..S'C-r; , ¡ ¡.-. ,_=" I ¡ -r- ~ i ~r ¡ ¡"'!..~?'~ ·;";5.';' .~"'-..:'" ~~1"..(.. " Exhibit 1-2. Midnight Sun Pool Participating Area _, a.. ~) 0° Jj. . «4 ,~--~~-'lþU~ ~ ) .~ ~ .; . ~ . . . .. .ete ~ . ~ fit ". OJ " .. . .. . -~..... ¡t\.:BE1" ST 1 -6- ADIJ28300' .~~~~....... (I .. , 1 mile . ~ i It . ' cO ~ . . .~ . . ~ - G '" ., (-. I - . · · 1- . =. -- , . . J ft:B) . . J . .~ .. . . ~ . ~ ~~--~ ..- ~ . . . ., In- - . ] 41 .. . .. . - . A -v 30 J þ J¡' \~!N I AK-17 'j -,-' A . ; i. - .J _.. _ ~J ! ~ Exhibit 1-3. Type Log for Midnight Sun Pool Kingak o .c: :I CD u.. (I) CD ~tt: :J c D:: ::I <Cø a..., :J.c ~.2» c " i HRZ o 2000 60 150 0.2 Strat. b{J ;'WUU 1 bU U.¿ OH.AF60_.AIT _5_.0 ARCO Alaska, Inc. Kuparuk Section of Well: E-100 API#: 500292281900 DATE: 21-Feb-1999 SCALE: 1:240 TVD LOG t (' . 11800 . 11750 - 8050 - - 8000 - 11700 . 11650 o Depth FEET SSTVD FEET 1 mile ..¡ ~ \. ( '\~¡ ~ . _ ~ J-...-----~----, - r ~ I Fawn Lk #1 t-¢- .---. ~ ¡ " .~-- .F-Pad ~ ~~ &1...-~ \ ~W ~ . , , ! -ÿ~ ' . J - , B¡¡ E,pad-'~'- . ;,-~- _ K.~:d ~r1_nn s ~ 50: . > ~ > .p. ,,-~""""""""'o/O....---...... ~ A _J:~~ ......~f~--a.. v.-.... ~ ~' ~. ~ _JF~ ~~~~ "'I!"_"'"'1l'~~_"I1P'Pf-""''t: .. " Exhibit 1-4. Top Kuparuk Structure .. . ~--...~ I~I('...-"-'. ^~, -J'~~"~ - ~ _ " ~ ~~ ~. : ~ ~- ~__-",~·,r ..-,-<-"'-..-'''''''--- ; ~~ ~;'.'.~ E~Pad · "_rL r ~ F·Pad ; . _; ~ _ r; .'".c-..~.~ ~ r-- ~-r" ... . . , ; i ; .. '.. ......J:~...,,~ . -_~A'~ ___ /..,. .._ _-__ __~-, I> _ _-_ --1,..... - -........""'"-'-"- ---~~ oj ~ Exhibit 1-5. Kuparuk Isochore ) __--...q, .r....~.¡ --- I ~ ~ '- / ~#1 /___v..J<- ..~~~- L M" - '-~._-- -¡ r' ; Fawn Lk #1 -Q- ~_I! .'.a'\ - -0--_"'__ _LYJJ. ,_ _.- - ....ðA........~·-- -_~;~"'" _~~ ___"__..::'#Cr_ _~_,_t--~· ''<'''-'''' .......':" .'__"""'~.--a........_.,.. .-'-'-~ ¡.... 1 mile J ( . ~ Exhibit 1-6. East-West Structural Cross-Section -~ =:--~ -~:-- --~ '= -~..~ -- -- , .. ~ .... 0, OIUJII'._II ...... ~~~..~ ARCO Alaska, lne. Wol: NPB_ST_1 ""'*.5QQ2't2O()ot1lOO DATE: œ-Ho¥-'" SCAlE: .:1200 1'VD lOO 12000 ft ARCO Alaska, Inc. _E.I01 -- DATE: 25-C:1c1-'Øi SCN.E: 1:12DD 1VD lOG - 6000ft- ARCO Alaska. Inc. w.., E·IDO APW: 5OD2I22I'. DATE: 25-OIS-ftll SCALE: 1:1200 1VD LOG - 8000 ft ARCO Alaska. Inc. _F.IS -- DATE:25-Oc:I-,.. SCALE: 1."1200 1W LOG ~ EAST A' MIDNIGHT SUN STRUCTURAL CROSS SECTION WEST A B South MIDNIGHT SUN STRUCTURAL CROSS SECTION B' North ,~~ ARCO Alaska. Inc. Wr/k.E·18 APtI; SOCI:282D4I100 DATE: ~19S1t SCALE: 1:1200 1"YD LOG 9500 ft ARCO Alaska. Inc. Wr/k.E-100 6000 ft - ARCO Alaska. lne. W,,: FAWN_lAKE_1 ..-_"'" DAÆ:2S-Q:I.1" SCALE: 1:1200 TYD lOQ AN;; 5Oa2R22It. DATE:2SOc:I-'tI!SII SCAL£:: 1:1200 1YD LOG -". CM.._ø....I._~ ~~~, =" ~-_. Exhibit 1-8. Kuparuk Net Sand '" .. i I .,.~~ . I /]f. hi. . ---~--~_.""~ .--' ~~. E P d ~; ~::;. . ...J8 a '. r,'~p ~u __'::.rf ~ ~ f ! , l · ; ~ · . · . . . ~----~- ~~~~......~_-...... , ~ ( ~ . L~ / ~~_. ~ -- ¡ ~....... ~ . ~ ~...7. ...O:-,tC ..~ _r tr---C; ~'>'~"""__'- Fawn Lk #1 -Q- ..J._~ . ' 1 L.. 1 mile .¡ -~~t . ... f 1 r ! -- ~ Fawn Lk #1 ~ J-¢- . ¡... 1 mile ~ - -,\ c , : '- / , ~ ~~""-~~j"""" ,'" ~ -, - ~ / !, Abe~#1 ~.4 .,/ L( ..- -~?~._._....._.~. ~"4:"- ~~ ~ ~. r-~ i .. ~ ~ ~ ~ 1 --&---~ J. ~ qt , _....<~ ~" ... . . . ; 0 r .F"'.Pad æ _../~~ ~ . ~p E",Pad _.......-r "'--r-- ~ ' t ~ ~ ~ ~ ~_.J.. 'r<i. .,! ~ ~ f ; ~ 1: ¡ ~ ~ J . . ) i \~ . ì ~I ""'""-r- ~ er-.h ~ ._-~ - :~K-pa~-r-·-- '; . ~ 1 1 ./ ~' . ~ , ~ ; ~ Þ¡ ~ ;. 1"I~~~'~~""~~!,~~""'''O'Z'-.:wk:o:I~~,",___ ~."- Exhibit 1-9. Gross Hydrocarbon Distribution t ( MIDNIGHT SUN RESERVOIR FLUID PROPERTIES INITIAL RESERVOIR PRESSURE AT 8010' TVD-SS 4045 PSIA BUBBLE POINT PRESSURE 4045 PSIA RESERVOIR TEMPERATURE 160 DEGF OIL GRA VITY 25 - 29 API RESERVOIR OIL VISCOSITY 1.68 CP RESERVOIR WATER VISCOSITY 0.39 CP RESERVOIR GAS VISCOSITY .027 CP SOLUTION GAS-OIL-RATIO (Rs) 717 SCF/STB OIL FORMATION VOLUME VACTOR (Bo) 1.331 RBL/STB WATER FORMATION VOLUME FACTOR (Bw) 1.045 RBL/STB GAS FORMATION VOLUME FACTOR (Bg) 0.699 RBL/STB Exhibit 11-1 :{ f ~ MIDNIGHT SUN RESERVOIR PVT PROPERTIES AS A FUNCTION OF PRESSURE Pressure Bo Bg Oil Viscosity Gas Viscosit~ Solution PSIA RBL/STB RBLIMSCF Cp Cp GOR I MSCF/STB 14.7 1.0541 19.4137 9.2900 0.0100 0.0000 I 154.7 1.0769 19.4137 5.7800 0.0114 0.0490 414.7 1.0992 7.0333 4.5100 0.0124 0.1020 814.7 1.1265 3.4663 3.7200 0.0134 0.1730 I 1214.7 1.1511 2.2654 3.1900 0.0145 0.2390 1614.7 1.1751 1.6681 2.7900 0.0157 0.3040 2014.7 1.1990 1.3149 2.4700 0.0171 0.3690 I 2414.7 1.2234 1.0858 2.2100 0.0188 0.4350 2814.7 1.2485 0.9296 2.0000 0.0208 0.5020 I 3214.7 1.2744 0.8213 1.8400 0.0228 0.5700 3614.7 1. 3011 0.7474 1.7400 0.0249 0.6390 4045.0 1.3311 0.6988 1.6800 0.0271 0.7170 I 4114.7 1.3348 0.6911 1. 667 4 0.0275 0.7313 4214.7 1.3418 0.6808 1.6561 0.0280 0.7490 I 4314.7 1.3487 0.6712 1.6462 0.0285 0.7666 4414.7 1.3557 0.6624 1.6376 0.0290 0.7843 4514.7 1.3626 0.6544 1.6300 0.0294 0.8020 I 5014.7 1.3974 0.6226 1. 6042 0.0315 0.8905 5514.7 1.4321 0.5995 1.5854 0.0333 0.9790 I 6014.7 1.4668 0.5777 1.5563 0.0350 1.0675 I I I I I I I Exhibit 11-2 293 420 22.7 23.5 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 Exhibit ll-3 0.72 0.72 0.25 0.25 0.25 0.55 0.55 0.55 1.00 1.00 1.00 1.00 1.00 1.00 0.00 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.5 0.5 0.5 0.3 0.3 0.3 1.0 164 405 258 692 1291 1558 741 639 680 3 22.9 26.1 23.6 26.0 29.3 30.2 29.2 28.5 27.8 23.0 RESERVOIR MODEL LAYERING AND PROPERTIES ~.. " '. IvlIDNIGHT SUN RESERVOI:k Exhibit 11-4 o 1 998.5 I I I I I I I I I I I I I I I I I I I FFM498.Feb2000.Update:WELl CURVES:MI DN IGHT _SUN:E-1 OO:GAS/Oll RA TIC -- FFM498.Feb2000.Update:WELl CURVES:MI DN IGHT _SUN:E-1 01 :GAS/Oll RA TIC '" MNS.Hist.Prod.data:WELL CURVES:<Text Data>:E-1 OO:GOR_ Test_History . MNS.Hist.Prod.data:WELL CURVES:<Text Data>:E-1 01 :GOR_ Test_History 2001.0 1 999.5 2000.0 Time (Year) 1 999.0 2000.5 \. 1\ .. ...., .. .. ...'_ II. .. .. .. .... .... .. & I II. .. ...... .. E-101 Under-Running rI "'- E-100 Coning ... Midnight Sun Reservoi r Model History Match Early Coning / Underruning GOR Behavior i3 6- V\ ~ - u V\ ~ 4- r:Z - o a 2- 8- ._,._.......,...._.\I_......,..-......~,." "",..". ........".,..\.._........~........""...,....'._............................,.._.......'............."....,.._...,..................................._................-.....,......._.._,..,...........,.._..__.._...._..........---._.........,.........."...,__..............._......_..,_...............,................,........._._............_......_......."...................._.. \.,' "','.,'".,,, FFM498.Feb2000.Update:LAYER CURVES:MIDNIGHT _SUN:E-1 OO:5:AVG GRID Bl .. MNS.Hist.Prod.data:WELL CURVES:<Text Data>:E-1 OO:Static BHP (PSIA) 2001 .0 1 999.5 2000.0 Time (Year) 1 999.0 2000.5 ·Statlc BHP @ 8010' TVD-SS Midnight Sun Reservoi r Model History Match E-1 00 Static Reservoi r Pressure (Gas Cap) 3400- -I 3200 1 998.5 rtl a. v: 3800- Q) ~ ::} ~ 3600- Q) ~ c... 4000- 4200- COMPARISON OF MODEL PREDICITONS AND FIELD PERFORMANCE ~ ( MIDNIGHT SUN RESERVOIR ---------------- 1 ??oo 8000 - "C 25 'is 6000 - 0) 1ã 4000 - a: Õ 2000 - 0 1998 "C 25000- - 'G fÞ 2??oo- :Ii i 15000- C'CJ '; 1??oo- C'CJ CJ 5000- MIDNIGHT SUN RESERVOIR PRODUCTION AND RECOVERY PROFILES FOR PRIMARY DEPLETION Oil Production vs. Time 2003 2008 Year Gas Production vs. Time 3??oo - -"'-"'- -- o 1998 2003 2008 Year 25 ___Oil Rate J: GOR -'- 20 .c 'is ~ 15 15 fÞ :Ii - 10 r£ o CJ ....5 . 0 2013 2018 2013 2018 16000 - 14000 ~ "C 25 12000- - fÞ 1??oo- 0) 1ã 8000- a: ¡ 6000-' - C'CJ 4000- ;: 2000 ~ o 1998 Water Production vs. Time 50 o 40 ~ ~ ~ 30- > o CJ .! 20- Õ Exhibit II - 5 2003 2013 2008 Year Oil Recovery vs. Time 2003 2008 2013 Year - - - 2018 ~~--. 2018 ---------------- - - - MIDNIGHT SUN RESERVOIR PRODUCTION AND RECOVERY PROFILES FOR UPSTRUCTURE GAS INJECTION Oil Production vs. Time 1 ??oo 70 8000 - . 60 '0 -'- 50 oS :c ~ 1;) 6000 ~ -40 Ü or ' (I) œ :æ 4000 -' - 30 .. a: a: Õ 0 - 20 CJ 2000 - 10 0 0 1998 2003 2008 2013 2018 Year 6??oo 5??oo - " ;;::: ~ 40000- :E i 3??oo - cu a: 2??oo- tn cu CJ 1??oo- Gas Production vs. Time o 1998 2003 2008 2013 2018 Year Water Production vs. Time 16000 14000 - '0 :c 12000- - tn 1??oo- or œ 8000- a: G> 6000- - cu 4000- 3= 2000 - o 1998 2003 2008 Year 2013 2018 Oil Recovery vs. Time 50 ~ 40- o ~-----"',. ~ 30- > o ~ 20- a: Õ 1 2003 2008 2013 2018 Year Exhibit II-6 --------------- MIDNIGHT SUN RESERVOIR PRODUCTION AND RECOVERY PROFILES FOR MIDFIELD WATER INJECTION Oil Production vs. Time 1 ??oo 8000 - . " 2i ~ 6000 ~ 0> 1i 4000 - a: Õ 2000 ~ 0 1998 2003 2008 Year Gas Production vs. Time 3??oo -- -- - 25000 - ~ en 2??oo ~ :æ of 15000- 1; ~ 1??oo- co CJ 5000- o . 1998 2003 2008 Year 7 ___Oil Rate X GOR - 6 -5,g 1;) - ~4ü en :æ -3a: -2 g ~1 o 2013 2018 2013 2018 Water Production vs. Time 16000 ' 14000 .., " 2i 12000- ~ 1??oo- 0> 1i 8000- a: . œ 6000- - co 4000- 3t 2000 ~ o 1998 2003 2008 Year Oil Recovery vs. Time 50 '# 40- ~ 30 ~ > o ~ 20- a: Õ 10- o 1998 2003 2008 Year Exhibit II-7 - 2013 2013 2018 ~~~ 2018 I I I I ~ ."'. '. ~ . . ~'.. :,'~,<. ::.:,', '~-,'..~-;..: '~~:_~~.:.,- ;.~....~ :~:~·~.~'-,·~·"~:I- ;..:....rlj'...:..._-:~'-~~;..~~~-,;. :-.,; Mi~nìght,S~nDe~ê¡oÞi11~nt: .. . ~:.. .,. .'. '.,~;} . ~ '. ·t~1;.':~·'.""~::.~·J,,:~';'~""'~':': "'~'." ·1', ..... ..w"'~_~ ,,' ;..."".- ,., M",... ; ..~...,~ ',"~-" . '~"'" "F' ;P'A' "'D· '. :.\ ::.-:' ....( . ..' '... .>.' ,"', .' . ;J1.'" ~\:.Xf~'; . !,,:"\.o".. . ..' i!~.. ~~Ii".~iy;.. . . ..,.: .....: ". ·~l.~.,...·~,. ...."'.".;..~:.. ..., ....~~. . '. ....~Y.'..., . ;It ' .. ..........j " . ._M, ":,"~' . '.., .. .~.' .... ),.E 'PI-\ L·Q1f"-.. ·l··~·· ·'.1. '.-.Í¡\...:::\,~ ~,_~~.;$ '" J.. j . ".J'." ",..-~ ' . ' .' ~~~ .... i' . t, ... . ,!< ...... .... .,..,>'/?-l. ,t'... . ....... .'. '. . ;: "t, " '\ . .,,/ . :1' PROJECT' . (:It· ._,C"'~'.' .~-"~"'~'-.·--t·o':'····'·"·-:~·~~""';"'.--·· .. ;..-..::'>:;......~..,......, .... ..,... ';" "'-, '. ':;.:,j,"".' "> .' " ... '.' , ...".. .".' ~( " .~. ¡'.', ."' . ". .., AREA· . rJK.' 'G~.Mf' J~~~~' ~ G 'PA(D ,/" .... I . . ...: .' r'\, ,~,~ ' 'ÿ;"J I~r . '¡ 'Æ/' , .' '. l· .' I '..',~: :,~ t~·,;;o"" .:' .,~, . ¿.,'!., ~ ;-..\ .j' ". ; . ''I:' I ' . ,., ::,'. : ~."",.-r~-¥' .':1, /,~r~~\" , . . ~ f' J' . ".',' .. . , ,~.N..,\....' . . . ¡: ' ' """'1",) , . I. I " 'J 'Ä)~~ '~"'" .,'J.. ;, : \,' '. " I :.j' I . ,f' :')1 c..j\· ','. ¡ . f:' "'. \.. . ~ " . . ~. " "ce:p, ~"(, , .t , l,~ C 1'\i¡.' . ; I- ' .¡ .: t ~ ,.f , j~.·.If~:~, . , . t ¡-I,'. .' ~. L. " : ~', . " "';j~" . :~, .,.:' .:. t,: '. ., ~ ."~. . ¡ , .' J;¡"J."....~....\.-\, .'if'.' . L..~.J~~\....::.L:L_.H_.;._:;...J\.l· . '¡".'j .:: : ' . :~,~,,', \. '!, '~, G'C' "1 . i" :.. :"l . ,,; '\ ¡ , ","'.. t, ¡ ~ . .' , . '1:" (.,.. ' : . 'I' :' . i ··I~~.,.I~~ ,',', . ..".' (G'~'>' .;: :/'r,.;. ./~ >;1\ 'J...... . :' .':: . \ .' . ~" " itl' ,'. " ), ··l . .... t I :~ . ..~~;,id'i \'..' , . . : . '~";~'. :., )i~:~J~.j, /" ,~ . '1 '. '" qr~S1' Ii, ~,"", ,,"." ,..,"'~" ,,' ¡:,I":L... :( r '. l~1'~";(")., ~..~ ,r:,;;··" I. . ,...,...»-.......~' r:~~' t... I;.'·~' :lS' . ..... .... ¡ .' ·~t..:' . ,-.1 ...",. I ~',",' " . ." .1""'" I ;:)/: ¡,. "",,,.,...,'.. '... ....~ .:~:.,..,' . .'~~~:"1; ,'. ....' " ,'.,....':~ "~. . , , .', :..~:: :: .' ,.,'~ -:"""\';I)~:,~~~,"'..':,..~....--.,,-.......... '. .', ':.' ;';'~~:'.", ..... :,..,..·.·..·.·,l ¡ .;' . : .i:-,,-. """'{~)1 .~ .... -,'.....~,: . , " J lo.,~':;.'c./>.·:.,.,_.};:t':··. .. ... ...... ·\~~:~~,!N~~'~·:· ···~"\\~!!r!:1 c. .P~..~.:,>. '.~::~~.¡ ¡ '....,...'~ '. , .. . . .,' :'ö"'<ï: ~ ..~;i.;nJJ .~~., ,'. ~,','''''' , . .' ~'I' . ..... i. I I I I .... . I : ·:ð· I . r.. ~'It~~ I I I I I I I Exhibit 111-1 I Facility Location Map I ~3 I~ .t:~ .' Flowtlne- Midnight Sun Equipment IPA Flowline· D Skid· Midnight Sun Equipment * Midnight Sun/lPA Tie-In Point I I I I I I I I I I I I I I ~ .¡,. [!Ü I - . J ,l i ,,,,,¿,,.., ,,:.., ........"J....". .~, =.:.::=".~.=..,:.,=..:,..~,,:.. ,=..:....:,:",,:.,=..:,,=,,~ .'::..:..~.,." MS Pwr Line from GC1 (Meter at GC1 not Shown) '"''''''''''''''''','.".'',''' ............-..,......".,.. ,..""..",....,..' ~ --a 6 o E-101 I --06 , I --a 28 'I " 2 220 . r i I -18'" 33~ I -U,.o I ;-" 030. 21 · ',:" 25 I 29~r , L..a17, 36 D , --a24A, =~r:.. ~~ %1~ -I Lö32 18Ao I' H ~39 37 D ~I' :_.,.;.r-) ~ ~"'75i, :. ';,.. . lL~.,! IPASlots~~. 5410 I!!J '. ~ /' - Metering Skid .... RELIEF PIT 11 ' I Existing E-100 & ~... E101 Well Lines , " . Cla88l1led 89 Mkt'ahl Sun Equlprrent tor I8tm 01 FSo\ per Section 4.2 --a 1 I . FlARE PIT ~;; -038 ~ D 7· I .. o E-102 L, d !103 (contlngen,t well) I .~ Q 9A C' E-100 'wi ::I 10 I . ESP Pwr & Ctrl Skid ,_.~ E-110 sw . ~ E-111 sw ,II ~ _!3_'.1õ I N' Switch Gear Skid '. 0 E-104 (contingent well) I ra1~! 1-J-031 I I, . 13 ! I . D 141 a 1SA WELL PAD E Midnight Sun Development as of January 1, 2000 "/' roFr Exhibit 111-2 Schematic of Pad Layout (' if ------------------- .------ Power Cable from GC-1 Switch Gear Skid Exhibit ID-3 Source Water Injection System ------- -, I L____ Pwr & Cntrl Skid Pwr & Cntrl Skid E-100 Well Line r-'-'"~-':"_" ,.----- - I I I I I I I I -------------------~ , p.~ ESP E-110 E-111 ~ E-100 Well: E-100 ftKB 2245 - 3405 - 3410 - 6760 - I 10100 - 11609 - 11610- 11620 - I I 11635 - 11636 - 11645 - 11646 - 11647 - I 11648 - 11775 - I 11780 - 11785 - 11790 - I 11855 - I 11870 - 11871 - I 12900 - 12901 - 12902 - I 12903 - 12904 - 12905 - I 12906 - 13024 - I 13275 - I SSSV NIPPLE NIP PKR NIP WLEG Perf PKR NIP NIP ... .':::¡,; . ',::,'::~; {,¡~ ;"~ ::.¡~ :'~':. , ..!'~~ NIP II~ I~ ',",:,;, . " ,~',.'" ~ ( Exhibit IV -1 E-IOO Wellbore Schematic WEB Date: 4/10/00 E-100 API: 500292281900 SSSV Type: Annular Fluid: Reference Log: Last Tag: 13023' ELM Last Tag Date: 3/15/00 Well Type: PROD Orig Compltn: 12/15/97 Last W/O: Ref Log Date: Angle @ TS: deg @ Angle @ TO: 22 deg @ 13284 Rev Reason: SBHP Last Update: 3/16/00 Safety Notes Date Note 11/20/98 Minimum 103.813" SSSVLN @ 2242', 'X' NIPPLE @ 11609', 'X' NIPPLE @ 11635' 12/24/98 'XN' NIPPLE ~ 13024' HAS XXN PLUG General Notes Date Note 11/20/98 STATUS: ACTIVE Other (plugs, equip., etc.) - JEWELRY Depth TVD Type Description 2242 2168 SSSV 4.5" HES, 'HXO' SVLN ASSEMBLY NIPPLE 11609 8007 NIP 11620 8015 PKR 11635 8025 NIP 11645 8032 WLEG 11852 8176 PKR 11870 8189 NIP 12900 9066 NIP 13024 9181 NIP Cas i I]gString$~ All Size Weight Grade 9.625 47.00 L-80 7.000 29.00 L-80 T"'binQStrinQs~AII Size Weight Grade 4.500 12.60 L-80 4.500 12.60 L-80 GasL.:iftMa.nd relsNalves Stn MD TVD Man Man V Mfr V Type V OD Latch Port TRO Date Vlv Mfr Type Run Comment 3401 3072 CAMCO KBG-2-LS CA 1.0 TEGRJO.OOO 0 11/30/98 TO: 13361 ftKB Max Hole 57 deg @ 3950 Angle: . 4.5" HES 'X' NIPPLE 7" x 4-1/2", BAKER SB-3 PKR 4.5" HES 'X' NIPPLE Wireline Entry Guide BAKER ZXP PKR 4.5" HES 'X' NIPPLE 4.5" HES 'X' NIPPLE 4.5" HES 'XN' NI PPLE, w/ XXN Plug (set 1/11/98) Top o o Feet Description 4441 SURFACE 12906 PRODUCTION Bbn 4441 12906 Top o 11852 Feet Description 116464.5"TBG 1425 4.5" LINER Bbn 11646 13277 RA SHEAR OK OK OK OK OK 1.0 TEGRJO.OOO 1.0 TEGRJO.OOO 1.0 TEGRJO.OOO 1.0 TEGRJO.OOO 1.0 TEGRJO.OOO o 11/30/98 o 11/30/98 o 11/30/98 o 11/30/98 o 11/30/98 2 5101 4079 CAMCO KBG-2-LS CA 3 6751 5069 CAMCO KBG-2-LS CA 4 8441 6069 CAMCO KBG-2-LS CA 5 10094 7067 CAMCO KBG-2-LS CA 6 11543 7964 CAMCO KBG-2-LS CA Perforations'Summary Interval TVD Zone Status Feet SPF Date Type 11775- 8122-8136 2041/19/98 11795 13150 - 9298 - 9303 13155 13155 - 9303 - 9312 13165 Comment 5 612/26/9' 34J HMX 412/20/9' 10 ID 3.810 3.810 3.880 3.810 3.960 4.380 3.810 3.810 0.000 iÎ II, ( EXHIBIT VI-l AFFIDA VIT I I STATE OF ALASKA THIRD JUDICIAL DISTRICT I, J. W. Groth, declare and affirm as follows: I I I I I I I 1 I' I I I I I 1. I am the Supervisor of Eastern Satellite Development for PHILLIPS Alaska, Inc., the designated operator of the Midnight Sun Participating Area, and as such have responsibility for Midnight Sun operations. 2. On MAy ~ , 2000, I caused copies of the Midnight Sun 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: PHILLIPS Alaska, Inc. Attention: Mr. 1. W. Groth P.O. Box 100360 Anchorage, AK 99510-0360 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: Mr. Ken Boyd P.O. Box 107034 Anchorage, AK 99510 Dated: rÝl ~ 3' ,2000. ~,~~~~ J. W. Groth ·3....& ~ i Declared and affinned before me this -= day of 1"'-0..6 , 2000. \t((({{((((f. l \\ \0\..\..5 TE/iI,rl"l",r \.".~ .' . . . 'v ,... ~ ".' " '. * ~ ~ t.q' , ., ~ '\ . . -;.. ...... ,''''' ,.. ' ..... '-- ' , J....."{ '!>J . - ....... ~. 0 ' oo¡;; . ce::: '- >- . ß.f'},:/ . ~ ...... :::: œ:. z ..~v' .0,)..... -:::. ~', ..":Þv,' : "'f.':::::: :::'Y'· ~ ,~~ -' þ,. . '..Irt ~ ~ ~ . . . . .:,.(}~":V ......./ *.. '~r..\.\"" \' //j ~~, \\\ JJ)}))))))) ~~J-.~ ~;;y-;ublic~ and for Alaska My commission Expires: í h ~ \-Zc.o I " I I I I I I I I I I I I I I 2600 I Non Marine 2700 T·8 I c 0 .- .. ca : IT-8 Marker E ... 0 LL ~ 0 3400 . ~ ... 3500 . .- C ca T·5 I > C) ca -I I en 3900 4000 4100 4200 T-3 4300 4400 Water Source Intervals OH.GR_BCS_S_1 30 GAP 4C o OH.GRj,CS_S_, C ::0 C."J' :<r. ~ OH.GRj3CS_S_' c ~TVD ¡':':'Z' ': 68.CfRÞ(R'...1: ):~::f: FEET o GAP 1~ Shallow Section Type Log E-16 Source Water Intervals Exhibit VI-2 ( ( ( EXHffiIT VI-3 DS-15 PRODUCED WATER SAMPLE ANALYSIS DS #15-6 Cretaceous Water Analysis, February 15, 1990, Sample No. 17241 DETERMINA TION VALUE 6.4 47005. 0.178 15850. 1260. 890. 12. 137. 60. 28439. O. O. 348. <1. <1. 9. <1. MglL OHM-M Mg/L MglL MglL Mg/L MglL MglL MgIL MglL MglL MglL MglL Mg/L Mg/L MglL I PH Total Dissolved Solids Resistivity @ 68 degF Sodium Ca1ci urn _ Magnesi urn Iron Barium Strontium Chloride Hydroxyl Carbonate Bicarbonate Sulfate Fluoride Silicon Aluminum I I I I I I I I I I I I UNITS EXHIBIT VI-4 GC #1 PRODUCED WATER SAMPLE ANALYSIS GC 1 Produced Water Analysis, December 17, 1998 DETERMINA TION VALUE UNITS 7.0 19985. MglL OHM-M 7420. MglL 190. MgIL 78. MglL 5. MglL 3. MglL 21. MglL 11946. MglL MglL MglL 1630 MgIL 293. MglL <10. MgIL 29. MglL <1. MglL I I I I I I I I I I I I PH Total Dissolved Solids Resistivity @ 68 degF Sodium Calcium Magnesium Iron Barium Strontium Chloride Hydroxyl Carbonate Bicarbonate Sulfate Fluoride Silicon Aluminum #4 , ') ) Notice of Cancellation of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Midnight Sun Pool, Prudhoe Bay Field - Pool Rules ARCO Alaska, Inc. by letter dated February 17, 2000, petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony to establish pool rules for the Midnight Sun Pool, Prudhoe Bay Field, on the North Slope of Alaska. . The hearing previously scheduled for April 4, 2000, has been cancelled. A new Public Hearing Notice will be published when the future hearing date is determined. ~~~ Camillé Oechsli Taylor Commissioner Published April 1, 2000 ADN A0-020l4030 ORIGINAL ) Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 AD# EDITION DATE PURCHASE ORDER ACCOUNT 331557 4/1/2000 02014030 DN STOF0330 STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, 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 language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all saiâ time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was 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 said period. That the full amount of the fee charged for the fore~oing publication is not in excess of the rate charged private indIviduals. C C\ \ Legal Clerk CR..SC,~~ UQ,~~Q. Subscribed and sworn to me before this date: /1 LÞU /J t/l¡- _.Y S; ~ Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: ç~ ~ tug,! -f$ullm{ ¡,¡¡f[rr((((" \\\' '1" \\\. ~\'\~ . ~ui.. I"~- 0- q,«;. .' --;.. ,<'0 -::- t :"~OTAJ?>'~ ~ ___ r - ::: : Þ(j°L'C .... ~:() Q .::::- -' ~~ --- .L~.· ..::::- -'. c..'Ç" . :', --::.. , '. OF ALþ..~ . :y ......../ . . . . . . '\'\ ././J * '\\\ .JJ})j)JJJ¡)ì\ 4Z~~gQ9Q PRICE PER DAY $47.73 $47.73 :.":,··",.,""i,""'·',·'.("""''''''',,, , 'Notice d",cancellation r of Pub,ic Hearing STATEOF'AL.ASKA' Alaska Oil and Gas COflservation 'co,:"ml~si~n Re:; 'Midni'9htsU,'n: p,ool. p'rÜ,dho~ ,B)Y' F i,eld . Pool Rules '" ' ' , ARtO::A.îo'ska~.lnc. ~Y let- ter doted F.ebruary p, ,2000. petitioned, the Ala~ka ,O.Il and'Gas 'Con'serva,ttor Commissionun'der 20 AAC , ,25.520 to hold a public hear-, Ing,to present testimony to' establish pool. rules fOIi HIe Mid n i ght',S un'PoQ ¡¡:Pr ud- " hoe BOY Field, on'tl'le, North SIO~ of Alaska:,,<,',,',":" , ',T he: ~ea ~ i~~'~rèVÙ) U ~ I y' sc1eduled for AprH .4/9.900, has been, cancelle(~':.a.; ,n~w Public Hearln9;Notic~ win be published when ·the fu- turehearin9'dateis, det~r: mined. "'.'," ',::, :"\ . . ",'. ''':, , IsltamlllèOechsli Toylor', Commissioner . :Â()~O~PJ4()30, ',; ......, .... ,PVb.:,APril);2p9Q, RECEIVED t.PR 1 0 2000 Alaska Oil & Gas Cons. Commission Anchorage #3 ~ FRO.M: rRCO ALASKA FAX NO.: 9072634894 I' ...... ^RCOAIM~. Inc. ( Post Office Box 100360 AnçhorQQ., Alaøkø 99510..0360 Telephone 901276 1215 03-27-121121 ø4:22P P.12I2 ( ~~ ~~ G(~ater Pt. Mcintyre Area March 27, 2000 Robert N. Christensen, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage~ AK 99502..3192 Re: Request to Reschedule the Midnight Sun Hearing Dear Mr. Christensen: ARCO Alaska, Inc. ("ARGO"), in its capacity as Midnight Sun Operator for itself and on behalf of Exxon Mobil Corporation f'ExxonMobiln) and BP Exploration (Alaska), Inc. ("BPX"), requests that the Commission reschedule the planned April 4, 2000 public hearing on the application for Mídníght Sun Oil poor Rules. As we discussed with you last week, we believe it is desirable to hold one hearing to consider the pool rules and area injection applications at the same time. Accordingly, we request that you reschedule the hearing for a day that is convenient for the Commission in the first or second week in May. Additionally, as discussed at the meeting, the waiver of the GOR limit of 20 AAC 25.240 tor Midnight Sun is set to expire on April 1, 2000. Thus, if the Commission postpones the poOl rules hearing, we reques' that the Commission also extend the GOR waiver to August 1! 2000. This action will allow production to continue pending consideration of our proposal tha1 the GOR waiver be included in the pool rules. Please contact J. W. Groth (265-6846) or E. W. Reinbold (263..4465) if you have any questions or require additional information. Sincerely. ~~~ J. W. Groth RECEi~JED cc: D. W. Bose (AReO) M. P. Evans (Exxon Mobil) J. HurHman (BPXA) MAR ? OQ I).'"\¡"\t\ LV'J~} PJQ¡ska Od &. G~$ Cons. CQ,mmi1!'$,iofì! Anchorage Ztr"'- , fJ ~fo -, / ,- /' J ¿Á "";,,.~ 5 - f..::' . 0 ç,J 2/?-?- y~s 2- ,,<;:. ~ (p ¿. DC¡ 1Jo!J -1-Jlet ~ 2ß-I5ílt 5"4' 377~ St.· c(~, 37~ ófo J/ - ;J. 7;).;).. l;'6 '3 ~ L(¡lf ?~, · 11-'; ~ "1q~ - 1z,,¿V ?9s -..;/<2.?0 ?<73-¡2¿7 (PLEASE PRINT) - --4~.-n:{ - /kCo ~~~I ~C~ - ~?:C~ /::::.l7é . #ß!ð,/d '. - AR~ ~. \.. \- ,~'-C)~ ,,~ ~(ì.(' d ) ~l ì P S:e:.vA~_\/\. - A V:-~IO ThLd '~f'\t - AR(j) . MaV'5a({;t WOt't'Â - t!C(oh Mob; I "{a.Aí '-(t/Î ¡.)(À '5-dòrn -~vx ¿f\/I!lJJ ,I _ çr....Ji:(~;-/-r: ~{:.( ~ IJ ~ ~Q"-~~" / 13:/( ~ Yrin (,-fa d ~ 1if2 cn \ÞtJ\Ibi MA.HAI\I .. Aor~ U- (fod::; ~t-=b- . kat, GV )f¥t ~~/ #o6'r'~ ¡)éL¡" .)e~:~r· frO~r:{, TELEPHONE NAME - AFFILIATION /if~CÆr 2~ 2b{)Ò Date/Time ¡Y( /),..,0-6 ~ ~ / Meeting Subject ALASKA OIL AND GAS CONSERV A TION COMMISSION -..-.---- ---- ~~. ~~ ÞIfCO ...... .. .. . ~It IT~. " ..._ ~: ,.,. ........ . ... -..... <II ... U1d:)·"2 8 ')f\.~·O . _. _ ('I¡I"~." LV,)· ""--.. Âlašk"a Oil & Gas Cor\s.l!ômiTI~$S10n __,C .. -. ."...' f\.f1CnOI aijtJ ..." ..... - ... ..- ....-. . ~ .. .. .... :- -.... . ~- .. _.:-,. f4': 2~,J., <JJ:9'/ REC~j\¡~~J- __a ._ _. ~.. .,¡/ r~_ ~ç,s:- 0 g SL 6_ , PHONE.I: ,.... ROM! . 9ÄL{/ G~~ . ...'''' COMP~: 41) 6... ~.." ç . ........ LOCA nON: .¿} ? ç, -7 S</ L. '''~~': 'Þ' . \." . /J /) 1'0 , , LJIt/2. r~ '.. .0. .. 1.4~. F A·CS'IMJLE TRA~"SM1SSI0N Fax N~ '(907) 2ß.48H. . . Verify (907) 263-4M8 (AWjlw 3/;),1, '00 NUMBER Of PAGES: C +._ I DA TE: GREATElt POINT' McINTYRE AREA' .-.-""~~--","""'~ { ARCO AIMka. Inc. p_ àIcI Bal1 ooæo ~ Alub9S1ð "'. 1!hP~ _ .. _t~· (\ ~ t FR(lM:. ..~:"~co RLRSKR . . 134:22P P.13l 133-27-1313 FRX NO.: 91372634894 #2 ) ) Notice of Public Hearing ST A TE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Midnight Sun Pool, Prudhoe Bay Field - Pool Rules ARCO Alaska, Inc. by letter dated February 17, 2000, has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony to establish pool rules for the Midnight Sun Pool, Prudhoe Bay Field, on the North Slope of Alaska. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 AM on April 4, 2000, in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. 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 Diana Fleck at 793-1221 before March 29, 2000. Robert N. Christenson, P .E. Chair Published February 25. 2000 ADN A0020 14027 ) ) Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 Ad # Date Puchase Order Edition Account Price Per Day 294245 02/25/2000 02014027 ON STOF0330 $60.63 $60.63 STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, 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 language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged forthe foregoing publication is not in excess of the rate charged private individuals. Legal Clerk_~~~~~~~____ i" .~òtic;e~f~~bJiCHeøri~9-' i . .,...... STATE 'OF:~I:-ASI<Å'! : Alaska.qiHlnd'Gas I :..···fonserY:~t~()".~OI11~iS~iO!1., ..1 !..Re.:,...!V'Jdnigh,. ·,·su~,.PÒOI,! :'. ·~~.Yedsho...e. ,aa,".'¥.'. F.....i.eld....,·...··.p.O,..OI..· ../ f~ ,', '.'." :,.:,,: ',' .. ',' '·"1_,'" ":_: .. '::," . ", , ' , , .' ' .'.." , Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: !êb f ¡¿{)I))I -----2-4 -B- '+,,- -------- \.\.\ ~~'!. . . ~I..( r",.... ~ ~..' ___'. .0(\ ,.,. ~ <?.' -\.orA·~ '."""-;' ~ . ~ ~·t:'r . ::: "- ..-. := .. ÞOBL\C. ::: ~ . ~À~:;";" #"/ ~ ~ ;,:~-OF A\-~'" ~ ..; -' '. ..' ,'\ "'....... ....."......... \. /../'.J * '\ '\ JJ))})J})))ì\ if;~f~:Jj~!;JH~.:;I.i ~:J'~LU !..:JnoIOQ'PUbjçhear;! ,~~g tq;'pre",,,,nttf.'ëtimÓI1. . i.:'. I t~~' ,t~r~,';~; _ [s~~,:~', 't~:,;; f u;, ~,~; ; ...'iJ.:.......' .b......'.J._....... 1-.. ......'..IJ. ' .,J...r, .'...I...,r,...,.~.:..........,.'. ...1,.....)..." r,. .../ ~IVfJ'" vl~asKa. :, . ." , " ,'. .'., ""j,', ,A..·h.,.e....a,: ri.n. g. .......'W....i..'..'. Q...e. h,.e.l.d.at.·.'1 the. Alaska ·Oil . and .... G ,ConServ,ation, Còrnmissio~s . ~001: Ro.rC~Þin~ ."" Drive: I nch'Jro:¡~ ..I J' ~ '1 '" .; 1)1) ~I\'-Ú·I~I ':-C'~:I"~, ~~I~~,?~ contornlQnCewitlJ .'20' AAC I ~~,5.40. AII'i.l'!terested per, I '...... ..n.". ?.r;'.d.. ~.,,=,.....'..r,...::,,)..,¿ invited' i 'V .'~""':',r" 1"':,I"To.~r", .1 ...'.f. y~u.·areaper~'oÍ1 ,with a I' ,dlsa~I~tywho may need .0' :speCIC." ....n.'.o..d..ilica.tib.n .... in¡ orc:!er . to ,comment . or to attend the.. p.ublic hearing. please contact Diana Fleck ; at7?3-1221 before. March' 29 I 2000. . ",' , ~ROb. ert ~. Christenson. Ii .E.. Chair. " I I I I AO-02014027 Pub.: 2I~5, 2000 Subscribed and sworn to me before this date: ----lêJL~_~1r~!IL_-- #1 ) ) ARca Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 ~~ ~~ Greater Pt. Mcintyre Area February 17, 2000 Robert N. Christensen, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99502-3192 Re: Midnight Sun Pool Rules Hearing Request Dear Mr. Christensen: ARCO Alaska, Inc. ("ARCO"), in its capacity as Midnight Sun Operator for itself and on behalf of Exxon Corporation ("Exxon") and BP Exploration (Alaska), Inc. ("BPX"), requests that the Commission hold a public hearing pursuant to 20 AAC 25.540 and issue an order classifying the Midnight Sun Pool as an oil pool and prescribing rules to govern the proposed development and operation of the pool pursuant to 20 AAC 25.520. We request that you schedule the hearing during the week of March 20, 2000, but we also would be available any time in April. Enclosed are the rules that are proposed for the Midnight Sun Pool. In addition, we are prepared to meet informally with the Commission prior to the hearing to review the scope and content of the testimony to be presented at the hearing and to respond to any questions or concerns. Our preference would be to meet at the earliest convenience of the Commission, preferably within the next two weeks. Please contact J. W. Groth (265-6846) or E. W. Reinbold (263-4465) if you have any questions or require additional information. s//~. Iy, '/1... jAAA-- /t{Ij(M,-,~v.. £- 0W(; J. W. Groth . OR/G/NIL R t~ r F I \/-t D . \,,,, ""'" ¡; 'Ii cc: D. W. Bose (ARCO) M. P. Evans (Exxon) J. Hurliman (BPXA) F[:G 23· 2QOO Alaska DH & Gas Cons. Commission Anchorage .... ) ) Proposed Midnight SUD Oil Pool Rules In addition to statewide requirements, the following pool rules are proposed to govern the proposed development and operation of the Midnight Sun Pool. Rule 1: Field and Pool Name and Classification The field is the Prudhoe Bay Field and the pool is the Midnight Sun Pool. The Midnight Sun Pool is classified as an Oil Pool. Rule 2: Pool Definition T12N-R13E: Sec 25, S1/2; Sec 36, N1/2, SE1/4, E1/2 of SW1/4 T12N-R14E: Sec 29, ALL; Sec 30, S1/2, S1/2 of NE1/4, S1/2 of NW1/4; Sec 31, N1/2, SW1/4, N1/2 of SE1/4; Sec 32, NW1/ 4 T12N-R14E: Sec 28, W1/2, W1/2 of NE1/4, W1/2 of SE1/4 The Midnight Sun Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between measured depths 11,662 and 11,805 feet in the E-100 well. Rule 3: Spacing Minimum spacing within the pool will be 80 acres. The pool shall not be opened in any well closer to 300 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 at six-month intervals. Rule 5: Common Production Facilities and Surface Commingling (a) Prior to installation of a continuous metering skid, producing Midnight Sun wells will be tested a minimum of 2 times per month and production will be allocated by interpolating between well test resu Its. (b) After installation of the continuous metering skid, the requirements of 20 AAC 25.230 will be satisfied by measuring production from the Midnight Sun Pool as a whole, and then allocating that production to each well daily. (c) The allocated production for the Midnight Sun Pool will not be adjusted in conjunction with the IPA allocation factors (Le. the Midnight Sun allocation factor will be 1.0). Page 1 of 2 "'" ) J Proposed Midnight Sun Oil Pool Rules (d) The operator shall submit monthly reports containing daily production metering and daily well allocations. Rule 6: Reservoir Pressure Monitoring (a) A minimum of one bottom-hole pressure survey will be taken annually for the Midnight Sun Pool. (b) The reservoir pressure datum will be 8,050 feet true vertical depth subsea. (c) Pressure surveys may 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. (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 Midnight Sun 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 3300 psi at the datum or within 2 years 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 any other special monitoring. 4. Future development plan. The report will be submitted to the Commission by the end of first quarter of 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. Page 2 of 2