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Home My WebLink AboutAIO 021INDEX AREA INJECTION ORDER NO.21 Meltwater Oil Pool Kuparuk River Field 1. March 12, 2001 Phillips Alaska, Inc.'s Meltwater Area Injection Order Application 2. April 5, 2001 Notice of Public Hearing; Affidavit of Publication and Bulk Mailing 3. March 22, 2001 Lease Information (fax) 4. May 7, 2001 Confidential portion Meltwater Area Injection Order 5. May 7, 2001 Meltwater Area Injection Order Application 6. May 7, 2001 Sign -in Sheet for Meltwater Hearing 7. May 7, 2001 Public Hearing Transcript (Confidential portion in Confidential room under Meltwater CO 456 and AIO 21) 8. May 23, 2001 Letter from AOGCC to Phillips re: questions 9. June 6, 2001 Phillips' request for Aquifer Exemption 10. July 18, 2001 Letter from Phillips informing AOGCC that they are not seeking an Aquifer Exemption 11. September 27, 2004 Public Notice to amend underground injection orders to incorporate consistent language addressing the mechanical integrity of wells 12. December 21, 2009 Letter from CPAI to AOGCC re: Cessation of Water Injection at Meltwater 13. October 7, 2011 Interim Update: Meltwater Oil Pool Wells with Elevated Outer Annuli Surface Pressure 14. September 25, 2012 Administrative Approval to amend Rule 2 (AIO 21.001) } STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West ih Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF ) PHILLIPS ALASKA, INC. for an ) order allowing underground injection ) of fluids for enhanced oil recovery in ) the Meltwater Oil Pool, in the ) Meltwater Participating Area, ) Kuparuk River Field, North Slope, ) Alaska Area Inj ection Order No. 21 Kuparuk River Field Meltwater Oil Pool August 1, 2001 IT APPEARING THAT: 1. By letter and application dated March 12, 2001, Phillips Alaska, Inc. ("PHILLIPS") requested an order authorizing the injection of fluids for enhanced oil recovery in the Meltwater Oil Pool ("MOP"). PHILLIPS provided draft written testimony for Meltwater Pool rules to the Commission on February 14 and March 12, 2001 and supplemental information on March 22, June 6, June 19, and July 18, 2001. 2. Notice of opportunity for public hearing was published in the Anchorage Daily News on March 23, 2001. A second public hearing notice changing the date of public hearing was published in the Anchorage Daily News on April 5, 2001 3. The Commission did not receive a protest. 4. A hearing concerning PHILLIPS request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 333 W. ih Avenue, suite 100, Anchorage, Alaska 99501 on May 7, 2001. Concurrently, the Commission heard testimony to define the MOP and establish rules for its development. 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 san1e field, facility site, reservoir, project, or similar area. 2. The proposed MOP is located in the western portion of Township 8 North and Range 7 East, Umiat Meridian, on Alaska State Leases ADL-373111, ADL-373112, ADL- 389058 and ADL-389059. The MOP is located within and adjacent to the current boundaries of the Kuparuk River Unit ("KRU"), North Slope, Alaska. ) \ l Area Injection Order No 21 August 1, 2001 Page 2 3. PHILLIPS is the operator of the MOP. PHILLIPS, BP Exploration (Alaska) Inc., Unocal Corporation, ExxonMobil Corporation, and Chevron U.S.A. Inc are working interest owners. The State of Alaska is the surface owner. 4. PHILLIPS has applied to the Alaska Department of Natural Resources to expand the existing Kuparuk River Unit to encompass the southern half of the proposed MOP and approve a Meltwater Participating Area ("MP A"). 5. PHILLIPS drilled three exploratory wells, Meltwater North 1, 2 and 2A, into the proposed MOP. Well and 3-D seismic data have been used to characterize the hydrocarbon accumulation within the proposed MOP. 6. The proposed MOP is defined as an accumulation of hydrocarbons that is common to, and correlates with, the interval between 6411' and 6974' measured depth ("MD") in the Meltwater North #2A well. 7. The proposed MOP is a sequence of very fine to fine-grained sandstones and associated mudstones that are late Cretaceous-aged (Cenomanian-Turonian) and lie within the Seabee Formation. The MOP proposed by PHILIPS is informally divided into two stratigraphic units that are named, in ascending order, the Bermuda Interval and the Cairn Interval. 8. The Bermuda Interval is interpreted as a channel fill and lobate sandstone turbidite fan accumulation, deposited in a slope-apron environment below an incised Cenomanian-age shelf. This interval lies between 6785' and 6974' MD in the Meltwater North #2A well, and is the only demonstrated productive interval within the proposed MOP. 9. The top of the Bermuda Interval dips approximately 2 to 3 degrees to the east- southeast. Complex faulting occurs along the western (updip) margin of the MOP. Shale filled channel complexes and stratigraphic pinch-outs act as lateral boundaries for the MOP. 10. Hydrocarbons are stratigraphically trapped in the Bermuda Interval, and their distribution is controlled by the distribution of sand. No gas cap or water has been encountered in Bermuda Interval within the MOP. 11. The MOP Bermuda interval is the stratigraphic equivalent and has similar lithology to the Tam accumulation to the north. Drilling at Tam has shown these deposits to be compartmentalized, primarily due to discontinuous sandstone distribution. 12. Petrophysical log, conventional core, sidewall core and cased-hole test data have been used to determine Bermuda Interval reservoir properties. 13. The Bermuda Interval sands are fine to very fine-grained, lithic-rich, and have common mudstone laminations and interbeds. X-ray diffraction analyses indicate clay content ranges from 15 to 25%, but the clay minerals occur dominantly as framework grains rather than as matrix. 14. Sandstone cores from the Bermuda Interval average 200/0 porosity and 12 millidarcies air permeability. Facies dependent water saturation values calculated from well logs range from 32% to 450/0. Area Injection Order No 21 August 1, 2001 Page 3 15. Initial reservoir pressure is approximately 2,400 pounds per square inch ("psi") and reservoir temperature is 135° F at datum level 5400 feet TVDss. 16. Bermuda Interval crude oil gravity is 37° API, formation volume factor at reservoir pressure is about 1.33 reservoir barrels per stock tank barrel, solution gas-oil ratio is about 620 SCF/B, and the viscosity of the oil is 0.76 cps. 17. The Bermuda Interval original oil in place ("OOIP") is estimated to be 125 million stock tank barrels of oil ("MMSTB"), with an additional possible 7 MMSTB OOIP within the Cairn Interval (see Cairn Interval description below) 18. Approximately 3,000 feet of impermeable shale separate the top of the Cairn Interval from the Tabasco Sandstone equivalent, the first overlying potential reservoir zone. About 500 feet of shale separate the base of the MOP from the underlying I(uparuk Formation. 19. Recovery estimates range from 18% of OOIP by primary depletion to 29% with a waterflood (11 % incremental recovery). 20. Model studies of alternating cycles of water and miscible gas injection (MW AG) are estimated to increase recovery 20 % over primary depletion and 9% over waterflood. These model studies assumed a 20% hydrocarbon pore volume slug, which is approximately 46 BCF. Total recovery with an MW AG process is estimated to be 38% OOIP. 21. The MW AG project is scheduled to commence within six months of production start-up. Existing Kuparuk River Field facilities will be used to supply Miscible Injectant (MI). An 8-inch MI injection line will be constructed from Imu Drill Site 2N to the Meltwater Drill Site 2P. 22. MI and water will be injected to provide reservoir pressure support and to maximize recovery. As development matures, lean gas will be injected to maximize recovery of light hydrocarbon liquids injected as part of the MI stream. Produced water from the KRU and Meltwater will be the source of injection water. Imu facilities will be the major source of produced water, MI and lean gas. Produced water from Meltwater may provide an additional source of injection water. 23. MI and water well head injection pressures are expected to range from 2,600 to 3,600 psi and 1,600 to 2,600 psi, respectively. 24. PHILLIPS' modeling indicates that the maximum injection pressure is not likely to initiate or propagate fractures through the confining strata. 25. The chloride content in water derived from Meltwater cores is estimated to be 35,000 to 45,000 parts per million ("ppm") NaCI. Average salinity estimates from core plugs obtained in the Bermuda Interval within the Tam Oil Pool, located 8 miles to the north, is 30,000 ppm NaCl. 26. Wireline log analytical techniques, which comply with EP A recommended methods as described in "Survey of Methods to Determine Total Dissolved Solids Concentrations", (KEDA Project No. 30-956), were used to characterize formation water total dissolved solids content in the Meltwater Oil Pool vicinity. ) ) Area Injection Order No 21 August 1, 2001 Page 4 27. Analysis of potential underground sources of drinking water also included dipole sonic and mud log data. These data demonstrate that apparent aquifers in the Meltwater pool area contain significant hydrocarbon saturations related to either hydrates or free gas. 28. PHILLIPS interprets the Cairn Interval within the proposed MOP as a marine, contourite-like, channel fill sand deposit that formed in a base of slope setting. This interval lies between 6411' and 6785' MD in the Meltwater North #2A well, and is a potential source of hydrocarbons. 29. Exploration targets within the Cairn Interval are offset along the eastern margin of the Bermuda hydrocarbon accumulation and are down dip from the western portion of the field. 30. Reservoir quality sandstones have not been encountered within Cairn Interval, but may be present near the center of the proposed MOP area. This interval is expected to be a stratigraphic trap. 31. Phillips will attempt to evaluate the productivity of the Cairn interval early in the development of the Bermuda interval. 32. Communication between the Bermuda and Cairn Intervals is uncertain at present. It is uncertain if underground injection of fluids into the Bermuda reservoir will have any effect on potential Cairn reservoirs. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An Area Injection Order is appropriate for the project area in accordance with 20 AAC 25.460 3. The U.S. Environmental Protection Agency has exempted all aquifers in the existing KRU (40 CFR Subpart C 147.102). 4. There are no potential underground sources of drinking water in the Meltwater pool area. 5. 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. 6. Injected fluids will be confined within the appropriate receiving intervals by impermeable lithology, cement isolation of the wellbore and appropriate operating conditions. 7. Implementation of an enhanced recovery operation involving injection of alternating cycles of water and miscible gas, MW AG, will preserve reservoir pressure/energy and enhance ultimate recovery. 8. The proposed MOP water injection project will result in 20 percent (about 25 million barrels) increased recovery over primary production alone. ) ) Area Injection Order No 21 August 1, 2001 Page 5 9. Reservoir surveillance, operating parameter surveillance and mechanical integrity tests will demonstrate appropriate performance of the enhanced oil recovery project or disclose possible abnormalities. 10. 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 (to the extent not superseded by these rules), govern Class II enhanced oil recovery injection operations in the affected area described below: Umiat Meridian Township T8N Range Section R7E Sections 1 through 36: All State Lands Rule 1 Authorized In.iection Strata for Enhanced Recovery 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 6,785' and 6,974' MD in the Meltwater North #2A well. Rule 2 Fluid In.i ection 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 Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. Rule 4 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. Rule 5 Notification of Improper Class II In.iection The operator must notify the Commission if it leams of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. ) Area Injection Order No 21 August 1, 2001 Rule 6 Administrative Action Page 6 Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend any rule as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into a USDW. DONE at Anchorage, Alaska and dated August 1, 2001. Cæ~/lLlU~ Cammy OeWsli Taylor, -C~r Alaska Oil and Gas Cons rvation Commission ?1¡¡¿!::mmiSSioner Alaska Oil al1d Gas Conservation Commission ." Ju.f~~; M ' *L1.~r Julie M. Heusser, Commissionner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may tìle with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30 day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., lOth day after the application for rehearing was filed). OFFICE OF THE GOVERNOR, JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 LIBRARY OF CONGRESS, STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 US GEOLOGICAL SURVEY, LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 AMOCO CORP 2002A, LIBRARY/INFO CTR POBOX 87703 CHICAGO, IL 60680·0703 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 XTO ENERGY, SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 OIL & GAS JOURNAL, LAURA BELL POBOX 1260 TULSA, OK 74101 US DEPT OF ENERGY, ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 XTO ENERGY, MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 ') PIRA ENERGY GROUP, LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 ARENT FOX KINTNER PLOTKIN KAHN, LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT A V NW WASHINGTON, DC 20036-5339 U S DEPT OF ENERGY, PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 DPC, DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 ILLINOIS STATE GEOL SURV, LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN,IL 61820 MURPHY E&P CO, ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 IOGCC, POBOX 53127 OKLAHOMA CITY, OK 73152-3127 GAFFNEY, CLINE & ASSOC., INC., LIBRARY 16775 ADDISON RD, STE 400 ADDISON, TX 75001 DEGOL YER & MACNAUGHTON, MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 SHELL WESTERN E&P INC, G.S. NADY POBOX 576 HOUSTON, TX 77001-0574 ) NY PUBLIC LIBRARY DIV E, GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 US MIN MGMT SERV, CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 TECHSYS CORP, BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 SD DEPT OF ENV &. NA TRL RESOURCES, OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 LINDA HALL LIBRARY, SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 UNIV OF ARKANSAS, SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 STANDARD AMERICAN OIL CO, AL GRIFFITH POBOX 370 GRANBURY, TX 76048 H J GRUY, A TIN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 PURVIN& GERTZ INC, LIBRARY l 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON, TX 77002-2979 OIL & GAS JOURNAL, BOB WI LLlAMS 1700 W LOOP SOUTH STE 1000 HOUSTON, TX 77027 MARATHON Oil CO, GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON, TX 77210 EXXON EXPLORATION CO., T E ALFORD POBOX 4778 HOUSTON, TX 77210-4778 PHILLIPS PETROLEUM COMPANY, W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 EXXONMOBIL PRODUCTION COMPANY, J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 MARATHON, Ms. Norma L. Calvert POBOX 3128, Ste 3915 HOUSTON, TX 77253-3128 TEXACO INC, R Ewing Clemons PO BOX 430 BELLAIRE, TX 77402-0430 INTL OIL SCOUTS, MASON MAP SERV INC POBOX 338 AUSTIN, TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON, CO 80127 ) RAY TYSON 2016 MAIN #1415 HOUSTON, TX 77002-8844 PETRAL CONSULTING CO, DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON, TX 77042 UNOCAL, REVENUE ACCOUNTING POBOX 4531 HOUSTON, TX 77210-4531 CHEVRON USA INC., ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 WORLD OIL, DONNA WILLIAMS POBOX 2608 HOUSTON, TX 77252 PENNZOIL E&P, WILL D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 ACE PETROLEUM COMPANY, ANDREW C CLIFFORD PO BOX 79593 HOUSTON, TX 77279-9593 WATTY STRICKLAND 2803 SANCTUARY CV KATY, TX 77450-8510 BABCOCK & BROWN ENERGY, INC., 350 INTERLOCKEN BLVD STE 290 BROOMFIELD, CO 80021 GEORGE G VAUGHT JR POBOX 13557 DENVER, CO 80201 ) CHEVRON, PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON, TX 77010 MARK ALEXANDER 7502 ALCOMIT A HOUSTON, TX 77083 EXXON EXPLOR CO, LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON, TX 77210-4778 PETR INFO, DAVID PHILLIPS POBOX 1702 HOUSTON, IX 77251-1702 EXXONMOBIL PRODUCTION COMPANY, GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON, TX 77252-2180 CHEVRON CHEM CO,LlBRARY & INFO CTR POBOX 2100 HOUSTON, TX 77252-9987 PHILLIPS PETR CO, PARTNERSHIP OPRNS JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE, TX 77401 TESORO PETR CORP, LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO, TX 78216-6999 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON, CO 80122 US GEOLOGICAL SURVEY, LIBRARY BOX 25046 MS 914 DENVER, CO 80225-0046 C & R INDUSTRIES, INC." KURT SAlTSGAVER 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD, CO 80226-4541 RUBICON PETROLEUM, llC, BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 US GEOLOGICAL SURVEY, LIBRARY 2255 N GEMINI DR FLAGSTAFF, AZ 86001-1698 BABSON & SHEPPARD, JOHN F BERGQUIST POBOX 8279 VIKING STN lONG BEACH, CA 90808-0279 TEXACO INC, Portfolio T earn Manager R W Hill POBOX 5197x Bakersfield, CA 93388 H l WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 MARPLES BUSINESS NEWSLETTER, MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 GUESS & RUDD, GEORGE l YLE 510 l ST, STE 700 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA, 1026 W. 4th Ave, Ste 201 ANCHORAGE, AK 99501 FOREST Oil, JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 ) JERRY HODGDEN GEOl 408 18TH ST GOLDEN, CO 80401 JOHN A lEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 MUNGER Oil INFOR SERV INC, POBOX 45738 lOS ANGELES, CA 90045-0738 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 US GEOLOGICAL SURVEY, KEN BIRD 345 MIDDlEFIElD RD MS 999 MENLO PARK, CA 94025 ECONOMIC INSIGHT INC, SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 DEPT OF REVENUE, Oil & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 STATE PIPELINE OFFICE, LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF AIR & WATER QUALITY TOM CHAPPLE 555 CORDOVA STREET ANCHORAGE, AK 99501 DEPT OF REVENUE, DAN DICKINSON, DIRECTOR 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 ) NRG ASSOC, RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901- 1655 TAHOMA RESOURCES, GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 LA PUBLIC LIBRARY, SERIALS DIV 630 W 5TH ST lOS ANGELES, CA 90071 ORO NEGRO, INC., 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 SHIELDS LIBRARY, GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 US EPA REGION 10, THOR CUTLER OW-137 1200 SIXTH AVE SEATTlE,WA 98101 FAIRWEATHER E&P SERV INC, JESSE MOHRBACHER 7151ST #4 ANCHORAGE, AK 99501 DEPT OF ENVIRON CONSERVATION, DIV OF ENVIRONMENTAL HEALTH JANICE ADAIR 555 CORDOVA STREET ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 DEPT OF REVENUE, CHUCK lOGSTON 550 W 7TH AVE, SUITE 500 ANCHORAGE, AK 99501 DEPT OF REVENUE, BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 ALASKA DEPT OF lAW, ROBERT E MINTZ ASST A TTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 DEPT OF REVENUE, Oil & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 DEPT OF NATURAL RESOURCES, DIV OF Oil & GAS JULIE HOULE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 AK JOURNAL OF COMMERCE, Oil & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99501-3560 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 FINK ENVIRONMENTAL CONSULTING, INC., THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT lOOP RD ANCHORAGE, AK 99507 US BlM AK DIST OFC, RESOURCE EV Al GRP ART BONET 6881 ABBOTT lOOP RD ANCHORAGE, AK 99507-2899 ) YUKON PACIFIC CORP, JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 GAFO,GREENPEACE PAMELA MillER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES, DIV OF Oil & GAS BRUCE WEBB 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DNR, DIV OF Oil & GAS JAMES B HAYNES NATURAL RESRCE MGR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, DIV OF OIL & GAS JIM STOUFFER 550W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 ANADARKO, MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC, JUDY BRADY 121 W FIREWEED IN STE 207 ANCHORAGE, AK 99503-2035 ARLEN EHM GEOL CONSl TNT 2420 FOXHAll DR ANCHORAGE, AK 99504-3342 US BUREAU OF LAND MNGMNT, ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT lOOP ROAD ANCHORAGE, AK 99507 UOA/ ANCHORAGE, INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 ) PRESTON GATES ELLIS LlP, LIBRARY 420 l ST STE 400 ANCHORAGE, AK 99501-1937 DEPT OF NATURAL RESOURCES,·DIV OF Oil & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF NATURAL RESOURCES, DIV OIL & GAS WilLIAM VAN DYKE 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 DEPT OF NATURAL RESOURCES, PUBLIC INFORMATION CTR 550 W 7TH AVE, SUITE 800 ANCHORAGE, AK 99501-3560 BRISTOL ENVIR SERVICES, JIM MUNTER 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE, AK 99502-1116 N-I TUBULARS INC, 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADRILl-SCHLUMBERGER, 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 JAMES E EASON 8611 lEEPER CIRCLE ANCHORAGE, AK 99504-4209 AMERICA/CANADIAN STRATIGRPH CO, RON BROCKWAY 4800 KUPREANOF ANCHORAGE, AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 VECO ALASKA INC., f CHUCK O'DONNELL 949 EAST 36TH AVENUE ANCHORAGE, AK 99508 US MIN MGMT SERV, RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 US MIN MGMT SERV, FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV, RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 CIRI, LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 PHILLIPS ALASKA, LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA. KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 US BUREAU OF LAND MGMT, OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 JODY COLOMBIE 6811 ROUND TREE DRIVE ANCHORAGE, AK 99516 ) TRADING BAY ENERGY CORP, PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 US MIN MGMT SERV, RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS, MMS ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 PHILLIPS ALASKA, LAND MANAGER JIM RUUD P.O. BOX 100360 ANCHORAGE, AK 99510 PHILLIPS ALASKA, LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 PHILLIPS ALASKA, MARK MAJOR ATO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 AL YESKA PIPELINE SERV CO, PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 ANCHORAGE DAILY NEWS, EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 JWL ENGINEERING, JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 ) US MIN MGMT SERV, AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 GORDONJ.SEVERSON 3201 WESTMAR CIR ANCHORAGE, AK 99508-4336 US MIN MGMT SERV, LIBRARY 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 USGS - ALASKA SECTION. LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 ANCHORAGE TIMES, BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 PHILLIPS ALASKA, STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP, KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 AL YESKA PIPELINE SERV CO, LEGAL DEPT ' 1835 S BRAGAW ANCHORAGE, AK 99512-0099 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 NORTHERN CONSULTING GROUP, ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE. AK 99517 , ' GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE, AK 99517-1303 DAVID CUSATO 600 W 76TH 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 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 ENSTAR NATURAL GAS CO, BARRETT HATCHES POBOX 190288 ANCHORAGE, AK 99519-0288 MARATHON OIL CO, LAND BROCK RIDDLE POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, POBOX 196247 ANCHORAGE, AK 99519-6247 EXXON MOBIL 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, 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 L G POST O&G LAND MGMT CONSULT 10510 Constitution Circle EAGLE RIVER, AK 99577 D A PLATT & ASSOC, 9852 LITTLE DIOMEDE CIR EAGLE RIVER, AK 99577 JAMES RODERICK PO BOX 770471 EAGLE RIVER, AK 99577-0471 COOK INLET KEEPER, BOB SHA VELSON PO BOX 3269 HOMER, AK 99603 RON DOLCHOK POBOX 83 KENAI, AK 99611 DOCUMENT SERVICE CO, JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 KENAI PENINSULA BOROUGH, ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 ) ASRC, CONRAD BAGNE 301 ARCTIC SLOPE A V STE 300 ANCHORAGE, AK 99518 OPST AD & ASSOC, ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 MARATHON OIL CO, OPERATIONS SUPT W.C. BARRON POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL, KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 BP EXPLORATION (ALASKA) INC, SUE MILLER POBOX 196612 MIS LR2-3 ANCHORAGE, AK99519-6612 BP EXPLORATION (ALASKA) INC, MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 PINNACLE, STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES, DGGS ' JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 PHILLIPS PETROLEUM CO, ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 NANCY LORD PO BOX 558 HOMER, AK 99623 f ' PENNY VADLA POBOX 467 NINILCHIK, AK 99639 PACE, SHEILA DICKSON POBOX 2018 SOLDOTNA, AK 99669 AL YESKA PIPELINE SERVICE CO, VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 UNIV OF ALASKA FAIRBANKS, PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 C BURGLlN POBOX 131 FAIRBANKS, AK 99707 K&K RECYCL INC, POBOX 58055 FAIRBANKS, AK 99711 UNIV OF ALASKA FBX, PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 DEPT OF ENVIRON CONSERV SPAR, CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 ) BELOWICH, MICHAEL A BELOWICH 1125 SNOW HILL AVE WASILLA, AK 99654-5751 KENAI NATL WILDLIFE REFUGE, REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ VANGUARD, EDITOR POBOX 98 VALDEZ, AK 99686-0098 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 ASRC, BILL THOMAS POBOX 129 BARROW, AK 99723 UNIVERSITY OF ALASKA FBKS, PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 /. /i .~ "",. ~',~·O I $;;] ~,H ~ certh y Ü,:a~ 0\·,¡j .'. ..-.-..~,,,' """k"'~ of the aboVø}}2::";J. :r,;~ ·::~·~':/m2åijad to ~ ~ '~~"\f:O' '.,' ;,.'. 1-"0' ~,,:-,> '·:"'f~:'.'I~~ of of the îO¡l:..ï,~,.¡.;::~,.:I. I.:~,,:...., '_""·~'''5~~~ fflOOrd: /-;·11' æ /77- ¡::J ..' _....._____-.....--.LiC ) JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 VALDEZ PIONEER, POBOX 367 VALDEZ,AK 99686 NICK STEPOVICH 543 2ND AVE FAIRBANKS, AK 99701 FAIRBANKS DAILY NEWS-MINER, KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 DEPT OF NATURAL RESOURCES, DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 RICHARD FINEBERG PO BOX 416 ESTER, AK 99725 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 21.001 CONOCO PHILLIPS ALASKA, ) INC. for an order allowing ) Kuparuk River Field underground injection of fluids for ) Meltwater Oil Pool enhanced oil recovery in the ) Meltwater Oil Pool, in the Meltwater ) October 4, 2012 Participating Area, Kuparuk River ) Field, North Slope, Alaska By letters dated September 25, 2012, ConocoPhillips Alaska Inc. (CPAI) requests administrative approval for two injection wells in the Kuparuk River Unit (KRU) Meltwater Oil Pool to allow the continued injection of miscible injectant (MI) with the outer casing annulus indicating re - pressurization after pressure bleeds. The Alaska Oil and Gas Conservation Commission (AOGCC) is returning CPAI's administrative approval requests without action, and on its own motion is hereby administratively amending Area Injection Order (AIO) 021.000, Rule 2 to include an injection pressure limit. This approval authorizes the continued injection of MI into the Meltwater Oil Pool for enhanced oil recovery purposes until such time as additional AIO 21.000 amendments have been considered by the AOGCC. Rule 2 ("Fluid Injection Wells") is hereby amended to read as follows: 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. Surface injection pressure shall be limited to 2600 psi. Motivating this amendment and efforts further to revise AIO 21.000 are two issues: indications of MI migrating out of the authorized injection zone as defined and described in the AIO, and elevated outer annulus pressures in Meltwater Oil Pool injection and producing wells. MI Migration out of the Injection Zone. Interpreted seismic data provided by CPAI shows the existence of vertical fractures that are consistent with the bottomhole location of Meltwater Oil Pool injection wells. Based on the results and interpretation of the seismic, vertical fractures appear to have allowed MI to migrate above the injection zone. In response, CPAI has imposed a wellhead injection pressure limit on Meltwater Oil Pool injection wells to ensure the injection pressure at the sand face is less than 3400 psi, which corresponds to a pressure less than the leak - off test data gathered after drilling out of the production casing (top -sets the injection zone/producing horizon). As noted in AIO 21.000, there are no potential underground sources of drinking water in the Meltwater Oil Pool area. Elevated Outer Annulus Pressures. With the restricted injection pressure, data provided by CPAI indicates that the outer annulus pressure in wells has declined. Where pressures remain, the rate of pressure build-up in the outer annulus is manageable with periodic pressure bleeds. AIO 21.001 October 4, 2012 Page 2 of 2 Effective immediately the following additional conditions are imposed: 1. CPAI shall record wellhead pressures and injection rates daily; 2. CPAI shall submit to the AOGCC a monthly report detailing the daily monitoring of all Meltwater Oil Pool wells. Included in the monthly report CPAI shall submit OA fluid levels, well pressures, injection and/or production rates, and pressure bleeds for all annuli. Trends shall be evaluated and detailed; 3. CPAI shall limit the outer annulus pressure to 1000 psi; 4. CPAI shall immediately shut in any well indicating a change in its mechanical condition; 5. CPAI shall immediately notify AOGCC when a well is shut in for mechanical integrity reasons; and 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection. The AOGCC has scheduled a hearing on November 8, 2012 at 9:00am to consider the need for additional amendments to AIO 21.000. This Administrative Amendment will not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles and will not result in an increased risk of fluid movement into a USDW. DONE at Anchorage, Alaska and dated October 4, Cathy . Foerster Daniel T. Seamount, Chair, Commissioner Commissioner 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 ti as \, AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsiderati o maner determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsiderat n set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for recomidermion in whole or in part within 10 days after it is filed. Failure on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision sn TION a denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the dot 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 ease 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(6), "[tlhe 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 ran 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 Wallace, Chris D (CED) From: Rodgers, James T <James.T.Rodgers@conocophiIli ps.com> Sent: Friday, September 21, 2012 10:09 AM To: Wallace, Chris D (DOA) Subject: RE: Meltwater Update Chris, in response to your second paragraph, I assume being prompted by the question in our 9/18 meeting from Jim Regg asking why we currently had no Administrative Approvals (AA) for existing Meltwater injectors, following is our response. Meltwater's Area Injection Order (AIO) 21 is different from all our other Operated Asset's AIOs. It does not require or imply that CPAI needs Administrative Approval (AA) to operate the two injection wells that have outer annulus pressure (let alone all five Meltwater injection wells). I understand that Tom Maunder discussed this with the Well Integrity Team in the early days; however, they have found no written documentation of those conversations. Consequently, in answer to Mr. Regg's question, in the AIO's current state, no AA's should be required for Meltwater injection wells with pressure on the casing by casing annulus; therefore, CPAI has been operating these injection wells in compliance with that aspect of the AIO. Please let me know if you have any other questions. James Rodgers From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent: Wednesday, September 19, 2012 8:47 AM To: Rodgers, James T Subject: (EXTERNAL]RE: Meltwater Update James, Thanks to you and your team. I appreciated the open candid discussion and sharing of information, and was pleased that you were able to address our concerns/topics. 1 feel we have re-established a foundation of understanding and look forward to getting the orders in line to reflect our latest thinking and path forward. You mentioned that there has been some correspondence relating to Administrative Approvals/waivers/agreements for the operation and monitoring of the wells in the recent past. If you have that please send as it is unfortunately not captured in our files. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallaceR alaska.gov From: Rodgers, James T [mailto:James.T.Rodgers@conocophillips.com] Sent: Wednesday, September 19, 2012 8:30 AM To: Wallace, Chris D (DOA) Subject: RE: Meltwater Update Chris, l wanted to thank you and your Team for our meeting yesterday afternoon. 1 am very happy that it turned into more of a working meeting with a sharing of ideas. It was a huge help to us to better understand all the different perspectives regarding our plans going forward. The Meltwater Team will work diligently to amend the AIO. Appreciate it James Rodgers ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 25, 2012 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7°1 Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Seamount: Enclosed please find the request for Administrative Action per Rule 6 in Area Injection Order 21 on Meltwater injection well 2P-434 (PTD 203-153). Please call Martin Walters or me at 659-7043 if you have any questions. Sincerely, lei MJ Lo4and ConocoPhillips Well Integrity Projects Supervisor Enclosures ConocoPhillips Alaska, Inc. Kuparuk River Field, Meltwater Oil Pool 2P-434 (PTD# 203-153) Technical Justification for Administrative Action Request Purpose ConocoPhillips Alaska, Inc. proposes that the Alaska Oil and Gas Conservation Commission (AOGCC) approve this Administrative Action (AA) request as per Area Injection Order (AIO) 21, Rule 6. Meltwater injection well 2P-434 (PTD# 203-153) is currently operating in compliance with AIO 21; however the AA per Rule 6, will allow additional monitoring by the AOGCC for historic elevated outer annulus (OA) pressure on this well. Well History and Status Meltwater injection well 2P-434 (PTD# 203-153 was drilled and completed on Jan 1, 2004 as a water alternating gas (WAG) enhanced oil recovery (EOR) service well. It was placed on produced water injection in February 2004 and passed a subsequent state witness mechanical integrity test (MIT). The well was operated with WAG cycles until August 2007 when it was shut in. Elevated OA pressure above 1000 psi from the open OA shoe was reported to the AOGCC on April 12, 2004. Due to the language currently written in AIO 21 Administrative Action is not implied or required. In the time since the well has been shut in the OA pressure has dropped below 100 psi (see attached). The well has maintained tubing, packer, and production casing integrity as shown by the passing 4 year MIT's and pressure trend plots. Barrier and Hazard Evaluation Tubing. The 3-1/2", 9.3#, L-80 tubing has integrity to Baker Seal assembly @ 5538' MD (5141' TVD), based on the passing MITIA completed on 08/08/10 and historic pressure trends. Production: casing. The 7", 26#, L-80 production casing has an internal yield pressure rating of 7240 psi has integrity to the packer @ 5538' MD (5141' TVD) based upon historic pressure trends and MITIA's. Surface casing: The 9-5/8", 40#, L-80 surface casing with an internal yield pressure rating of 5750 psi set at 2421' MD (2356' TVD) has an open OA shoe, however has historically held elevated pressure showing casing integrity at that time. Primary barrier: The primary barrier to prevent a release from the hydrocarbon producing formation in this well is the production tubing. Second barrier: The secondary barrier to prevent a release from the hydrocarbon producing formation in this well is the production casing envelope should the production tubing fail. Well Integrity Project Supervisor 9/24/2012 Monitoring Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or surface casing above the conductor shoe it will be noted during the daily monitoring process. Any deviations from approved allowable operating annular and or injection pressures require investigation and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for MI or wag (if water becomes available) injection; 2. OA will be monitored daily and recorded for trending, 3. Monthly OA fluid levels 4. Perform an MITIA every four years; 5. Submit monthly reports of daily tubing, IA, OA pressures, injection volumes, and any OA bleeds; 6. Notify AOGCC and take appropriate action should the MIT, injection rates, or pressures indicate well integrity issues. Well Integrity Project Supervisor 9/24/2012 OHUKt VIF FTT IAP -- - OAP TWO Plot - 2P-434 200 3000 .... ... ............ .................................................. ........ 150 2000 100 E a JJIIJJII'' m Fn' .... ... .. .. .. ......... .IY �illhl ..... ................. 1000 t ! 9 01 -Jan -05 01 -Jan -07 01 -Jan -09 01 -Jan -11 Date 50 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to:(im.regg@alaska.gov; phcebe.brooks@alaska.gov; tron.maunder@alaska.gov; doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: ConocoPhillips Alaska Inc. FIELD / UNIT / PAD: Kuparuk / KRU / 2P DATE: 08/08/10 OPERATOR REP: Colee / Coleman - AES AOGCC REP: Robert Noble TYPE INJ Codes TYPE TEST Codes D = Drilling Waste Packer Depth G = Gas Pretest Initial 15 Min. 30 Min. A= Temperature Anomaly Survey W = Water Well 2P-419 Type In'. G TVD 5,202' Tubin 3,700 3,700 3,700 3,700 Interval 4 P.T.D. 2040170 Type test P Test si 1500 Casin 2,716 3,300 3,260 3,260 PIF P Notes: I OAJ 291 1 335 1 338 1 336 Weil 2P-420 1 Type In'. I G I TVD 1 5,428' 1 Tubing! 3,0501 1 3.0501 Interval 4 P.T.D. 2011820 I Typetest I P I Test pall 1600 1 Casingi 1,8501 1 1 1,7691 PIF I F Notes: Pumped 13bbls. With no pressure increase. I OAl 2911 1 1 275 Wel12P-427 Type ln'. G TVD 5,455' Tubin 3,100 3,100 3,100 3,100 Inlerval 4 P.T.D. 2020180 Type lest P Test pail1500 Casin 1,925 2,600 2,520 2,520 P/F P Notes: I OAJ 6751 6761 676[_676 Well 2P-429 I Type In'. N 1 TVD 1 5,218' 1 Tubingl 910 910 1 910 1 910 1 Interval 4 P.T.D. 2011020 I Type test P I Test psil 1500 1 Casingi 435 1,820 1 1,770 1 1,760 1 P/Fl P Notes: I OAJ 10 1 442 1 349 1 339 We112P-434 T eln. N TVD 5129' Tubin 1,625 1,625 1,625 1,625 Interval 4 P. T.D. 2031530 Type test P Test pail1500 Casin 5 2,390 2,290 2280 PIF P Notes: I OAI 1001 1011 1011 101 WeII2P-447 Type Ini. G TVD 1 5,226'1 Tubingi 3.5001 3,5001 3,5001 3.5001 Interval 4 P.T.D.2031540 Type test P I Test pail 1500 Casingi 2401 1,8401 1.8101 1,810 P/FI P Notes: I OAI 11751 11761 11951 1201 Well T e In'. TVD Tubin Interval P.T.D. Type test Test psil I Casingi I I IP!F Notes: I OA Well T e In'. 1 TVD I I TubingI I Interval P.T.D. T atest Test pail I Casingi I PIF Notes: I OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = No! Injecting A= Temperature Anomaly Survey W = Water D = Differential Temperature Test MIT Report Form BFL 11/27/07 MIT KRU 2P Pad 08-08-10.zls INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover O = Other (describe in notes) KUP 2P-434 ConocoPhillips Well Attributes TMe%r,AnLfOgIB8,MD TD \I w.naonsenuwi e.m x.m. vi.0 sum. m. ^�ORB� Ptl Bim'XNB� Itflfl, SSt5d Ot5� 14 BOYJ ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 September 25, 2012 Commissioner Dan Seamount Alaska Oil and Gas Conservation Commission 333 West 7°i Avenue, Suite 100 Anchorage, AK 99501 Dear Commissioner Seamount: Enclosed please find the request for Administrative Action per Rule 6 in Area Injection Order 21 on Meltwater injection well 2P-447 (PTD 203-154). Please call Martin Walters or me at 659 7043 if you have any questions. Sincerely, ,- 4,��r��G_,� MJ Loveland ConocoPhillips Well Integrity Projects Supervisor Enclosures ConocoPhillips Alaska, Inc. Kuparuk River Field, Meltwater Oil Pool 2P-447 (PTD# 203-154) Technical Justification for Administrative Action Request Purpose ConocoPhillips Alaska, Inc. proposes that the Alaska Oil and Gas Conservation Commission (AOGCC) approve this Administrative Action (AA) request as per Area Injection Order (AIO) 21, Rule 6. Meltwater injection well 2P-447 (PTD# 203-154) is currently operating in compliance with AIO 21; however the AA per Rule 6, will allow additional monitoring by the AOGCC for historic elevated outer annulus (OA) pressure on this well. Well History and Status Meltwater injection well 2P-447 (PTD# 203-154) was drilled and completed on February 6, 2004 as a water alternating gas (WAG) enhanced oil recovery (EOR) service well. This well has had cement pumped down the OA by the drilling rig to improve the cement bond on the production casing. Subsequently the OA can no longer be pumped into however the shoe still leaks. The well was placed on produced water injection in February 2004 and passed a subsequent state witness mechanical integrity test (MIT). The well was operated with WAG cycles until June 2010 at which time gas became the only fluid available for injection. Currently 2P-447 is shut in for reservoir management, however may be returned to service in the future. Elevated OA pressure above 1000 psi from the leaking OA shoe was reported to the AOGCC on March 30, 2004. Due to the language currently written in AIO 21, Administrative Action is not implied or required. Recently the Meltwater injection/withdrawal operating principles were changed to a lower injection pressure and a lower injection/withdrawal ratio (I/W). Since that change the OA pressure has dropped below 500 psi. The well has maintained tubing, packer, and production casing integrity as shown by the passing 4 year MIT's and pressure trend plots (see attached). Barrier and Hazard Evaluation Tubing. The 3-1/2", 9.3#, L-80 tubing has integrity to Baker Seal assembly @ 7429' MD (5232' TVD), based on the passing MITIA completed on 08/08/10 and historic pressure trends. Production casing. The 7", 26#, L-80 production casing has an internal yield pressure rating of 7240 psi has integrity to the packer @ 7429' MD (5305' TVD) based upon historic pressure trends and MITIA's. Surface casing: The 9-5/8", 40#, L-80 surface casing with an internal yield pressure rating of 5750 psi set at 2705' MD (2318' TVD) has a leaking OA shoe, however has historically held elevated pressure showing casing integrity. Primary barrier: The primary barrier to prevent a release from the hydrocarbon producing formation in this well is the production tubing. Second barrier: The secondary barrier to prevent a release from the hydrocarbon producing formation in this well is the production casing envelope should the production tubing fail. Well Integrity Project Supervisor 9/24/2012 Monitoring Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or surface casing above the conductor shoe it will be noted during the daily monitoring process. Any deviations from approved allowable operating annular and or injection pressures require investigation and corrective action, up to and including a shut-in of the well. T/I/O plots are compiled, reviewed, and submitted to the AOGCC for review on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for MI or wag (if water becomes available) injection; 2. OA will be monitored daily and recorded for trending, 3. Monthly OA fluid levels 4. Perform an MITIA every four years; 5. Submit monthly reports of daily tubing, IA, OA pressures, injection volumes, and any OA bleeds; 6. Notify AOGCC and take appropriate action should the MIT, injection rates, or pressures indicate well integrity issues. Well Integrity Project Supervisor 9/24/2012 - CHOKE FTP — — FTT IAP TWO Plot - 2P-447 OAP 200 3000 p ................... 1a. ,:: I;. _.............................,. _ ... _.. 2500.............................................................................. ...... 150 2000 .. .............................................. ......................... ...... a E m an 100 1500 ........w.......... ..... r ' U 1000 ........... ........ ,r.` ................ 500...................................................I..........' .............. ... I...�: 0 T i i t m 4 1 a 1 I ' 0 01 -Oct -11 01 -Dec -11 01 -Feb -12 01 -Apr -12 01 -Jun -12 01 -Aug -12 Date CHOKE - - FTP FTT IAP -- OAP 3500 ........................... TWO Plot - 2P-447 �I ............................ ... 200 3000 .................... .� . 150 2500 { .. ..... ...... . 2000 .. .. 1 . ... t M 100 �. 1500 . ... u 1000 .... I I i .... .. .. ...... 50 i 500 y. . .. .. .,.. 0 0 01-Jan-05 01-Jan-07 01-Jan-09 01-Jan-11 Date STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email lo:jim.regg@alaska.gov; phoebe.brooks@alaska.gov; tom.maunder@alaska.gov; doa.aogcc.prudhoe.bay@alaska.gov OPERATOR: ConocoPhillips Alaska Inc. FIELD I UNIT I PAD: Kuparuk / KRU / 2P DATE: 08/08/10 OPERATOR REP: Colee / Coleman - AES AOGCC REP: Robert Noble TYPE INJ Codes TYPE TEST Codes 0 = Drilling Waste Packer Depth G = Gas Prates( Initial 15 Min. 30 Min. A= Temperature Anomaly Survey W = Water Well 2P-419 Type In'. G TVD 5,2024"1Tubin 3,700 3,700 3,700 3,700 Interval 4 P.T.D. 2040170 Type tesl P Test pail1500 Casin 2,718 3,300 3,260 3,260 PIF P Notes: I OAI 291 1 335 1 338 1 336 Well 2P-420 I Type In'. I G I TVD 1 5,428' 1 Tubingl 3.0501 Interval 4 P.T.D. 2011820 I Type test I P I Test pail 1500 1 Casingi1,850 1,769 PIF F Notes: Pumped 13bbis. With no pressure increase. I OAJ 2911 275 Well 2P-427 Type In'. G TVD 5,455' Tubin 3,100 3,100 3,100 3,100 Interval 4 P.T.D. 2020180 Type test P I Test psil 1500 Casin 1,925 2,600 2,520 2,520 PIF P Notes: I OAJ 6751 6761 6761 676 Well 2P-429 1 Type In'. 1 N TVD 1 5,218' 1 Tubing[ 910 1 910 910 1 910 1 Interval 4 P.T.D.2011020 I Type test P Test pail 1500 1 Casingi435 1,820 1,770 1,760 PIF P Notes: I OAI 310 1 442 349 1 339 Well 2P-434 T e In'. N TVD 5,129' Tubin 1,625 1,625 1,625 1,625 Interval 4 P.T.D. 2031530 Type tesf P Test si 1500 Casin 5 2,390 2,290 2,280 PIF P Notes: I OAI 1001 loll loll 101 WeII2P-447 1T eln'. G TVD1 5.226'1 Tubingj 3.5001 3,500 3,500 3,500 Interval 4 P.T.D. 2031540 I Typetest P Test pail 15001 Casingi 240 1.840 1,810 1,810 PIF P Notes: I QAJ 11751 11761 11951 1201 Well Type ln. TVD Tubing!Interval P.T.D. Type testj I Test psi I Casin PIF Notes: I GA Weill I TyeeIn'. TVD I I Tubingj Interval P.T.D. T etest Testpsi[ Casing[ P/F Notes I OA TYPE INJ Codes TYPE TEST Codes 0 = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A= Temperature Anomaly Survey W = Water D = Differential Temperature Test MIT Report Form BFL 11/27/07 MIT KRU 2P Pad 08-08-10.xis INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance T = Test during Workover O = Other (describe in notes) ConoctiPhillips AL,r,,, In IngR I r ema�_ less S KUP 2P-447 Wetl Attributes Max An le & MD TO 4Ye11bare APINV/1 Fleltl Wme 501032046800 "'M'ATER VJeII Slalua Inel14'1 MD 18 IS Act BIm Ifln.) INJ 59.82 ],682.99 8,0150 crimmem X]s 1pPml pee Ars. bn SSSV: NIPPLE Lasl WO: fns inn. Keunt, I Rly S. ....le 2798 1nN2004 Mnm.nen pepin InKe) ane pne ---------L..t List1 :SW ],6]1.0 l=009 Rev Reason:REMSECSGID nme._ Ena Dae nnan 8152012 Casin Strin a Caeme N...lpnen string 9... CONDUCTOR 16 suing - 15062 Toploxal s.1 Dept 11- set D.0 1-. 9trluewl..' Dine... stanSTap Na 30.0 108.0 IWO 62.50 H40 VIEWED Caang Deaeapllon Suing O... SURFACE 958 String III 8.835 TopinKBl SnOvish 1.,. Sa DePtn(Np1- slruggs.. Shing- Suns Trip TMa 28.1 2,705.6 2,318.0 40.00 L -W BTC Canns De¢apllan suing O.., INTERMEDIATE 7 liul,g... 6.2]6 T,MBI Set DMIRR Sel DrPihRMR- SRw,W.... .M1in,... Suing Trip TNa 25.2 7,562.0 5,305.9 am LEO BTC -W Caslne IN -upon sung O... LINER 312 sing ID._ 2.992 Top lnKBl Set Depinll-Set DMbRW))- Sus'sa... Slang... Suing Tap Tura ],4155 8,010.0 5,546.3 9.30 L-60 SIM Line, Details Tep Nplu ITVDI Tori nom!... Top (1DtB IRKS) li Ium Dndlpbn Crimsem IDhn) 7,415.5 5,2262 5540 PACKER ZKP HR LINER TOP ISOLATION PACKER YJRIE BACK 4.73 9,434.4 6.23561 55]ONIPPLE RS PACKOFF SEAL NIPPLE 4.250 ],43].2 5,23].3 55]6 HANGER BAKER FLEXLOCK LINER HANGER 5.000 ), 4 S 5,242.8 55.99 SBE BAKER 8040 ]465.7 b,25Lllj CROSSOVER BUSHING 3000 Tobin SVin a TUElne baotlptim set DeNM1 n... set Depinlrvp)... going Wb.. 9ul-1 SDMa Trip TMa "14-1SUNg10... TI -3N 13"14-112 TUBING 4 ill 3.958 23.0 ],468.0 5,251.0 12.1 LEO IBT-M Com letion Details Trip(9epm JDD) Tripmn xriml... To nne nt I') lam osecn non comment I011nl 23.0 23.0 -840 HANGER --- -- 4.500 5027 502.5 4.98 NIPPLE CAMCO NO GO'OB' NIPPLE a875 ],365.] 5,197.0 M.27 SLEEVE BAKER CMU SLIDING SLEEVE ud3SIT OBPROFILE 3.9-15 -aa7-W 7.3824 5807.0 51.65 MPPLE CAMCO'DE' NIPPLE 11:3.]5- N0 G0PR0FILE 7.428.1 5.2!1.9 5555 LOCATOR G -U LOCATOR 3.010 7,429.3 5232.6 55.50EALASSV BAKER8040 SEAL w1112 MInESHOE 3.98" x 3.W TWO Perforations & Slots sm TppnW) elm RVDI D.n. Tri Me atm nxa Inxe) InKe) Zone Daro tem.. T cammeM 7,600 ],640 5,3254 5,315.)T -32P -M) ai(NW 6.0 APERF 2.0 "SD PJ Cmgs. SO Me Ines. )100 7,]80 5,3]5.] 5419.OT-3, W447 2n1 601PERF 2.SHSDPJr;MiSw0egpnlue ),) 7, 5,4]9.0 5429.9 T-3, 2P-041 25(Xxl1 1 6,01IPERF 2.9'H30 PJ Chrys,Wdeg phase Notes: General & Safety ane Deu AnRW VEREDOA: PSURE CHARGING FROM R RESERVOIR 6N42W1 NOTE: WARES 1252W8 Imul E: VIEW SCHEMATIC sh"ISSie SUtemllic9.0 Mandrel Details Sm To RKI Top Depth Irvol pIKB) Tep mel I') M.Me Mritlel op Pnl 9ury vnn Type c.mn TYp. von eIn (I -I rao aun IWURun Dae Cam... 1 ],316.2 5,1889 5403. CAMCO KB 62 1 Gas LIB pM V BK 0= 80 12) X12 ,~ R~~~~ Q ~ 1, A~ ~~ l %; I. {asks Oil ~ G«~ ~~r~~: ~~rrrlrrlissl~~ ConocoPhillips David Jamieson ~r9f,l~`s`~~~ Supervisor, GKA Reservoir Planning Greater Kuparuk Area ConocoPhillips Alaska Inc. ATO-1320 PO Box 100360 Anchorage AK 99510-0360 Phone: (907) 263-4027 Fax: (907) 265-6133 December 21, 2009 Dan Seamont, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7'" Ave. Suite #100 Anchorage, Alaska 99501-3539 RE: Cessation of Water Injection at Meltwater Dear Mr. Seamont, This letter is to inform the Alaska Oil and Gas Conservation Commission that water injection ceased in the Meltwater Field on October 15, 2009. On this date, the water injection pipeline to the Meltwater field was declared unsuitable for continued operation due to internal corrosion. Miscible gas injection continues to maintain a voidage balance with production in the field. As of October 15, 2009, approximately 37 BSCF of miscible gas had been injected in the Meltwater Field compared with the target volume in Area Injection Order No. 21 of 46 BSCF. This represents a pore volume slug of 17% of the 132 MMBO of initial oil in place, compared with the target slug size of 20% as stated in Area Injection Order No. 21. At this time, there are no near-term plans to restore water injection service to Meltwater. ConocoPhillips does not anticipate any recovery impacts as little or no reservoir pressure support has been observed to date from water injection, however some response to gas injection has been observed. Studies are ongoing to determine the future development options for the highly compartmentalized Meltwater field in light of the recent de-rated water injection pipeline. ConocoPhillips expects to complete these studies by Q3 2010 and will update the AOGCC in 04 2010. If you have any questions concerning this, please contact Adam Lewis at 265-6362 or Michael Braun at 263-4185. Sincerely, ~-- Davi amieson Supervisor, GKA Reservoir Planning Greater Kuparuk Area cc: Mr. Warwick King, CPAI Mr. James Rodgers, CPAI Mr. Darron Jackson, CPAI Mr. Paul Wharton, CPAI Mr. Don Dunham, BPXA Mr. Glenn Fredrick, Chevron Mr. Dale Pittman, ExxonMobil #11 17 FRANK H. MURKOWSK/, GOVERNOR Li KA OIL AND GAS 333 W. 7TM AVENUE, SUITE 100 CONSERVATION COMMISSION 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 mechanical 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 0 f Mechanical Integrity" Affected Rules "Well Integrity Failure and Confinement" "Administrative 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 AIO 16 - Kuparuk River 6 7 10 Unit; Tarn Oil Pool 6 8 AIO 17 - Badami Unit 5 AIO 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 AIO 23 - N orthstar 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 \VD-l 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-l 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-l DIO 7 - West McArthur 2 3 5 River Unit; WMRU D-I 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 Injection Order "Demonstration of Mechanical Integrity" 2 DIO 11 - Kenai Unit; KU 24-7 DIO 12 - Badami Unit; WD- 1, WD-2 DIO 13 - North Trading Bay Unit; S-4 010 14 - Houston Gas Field; Well #3 010 15 - North Trading Bay Unit; S-5 DIO 16 - West McArthur River Unit; WMRU 4D DIO 17 - North Cook Inlet Unit; NCIU A-12 DIO 19 - Granite Point Field; W. Granite Point State 17587 #3 010 20 - Pioneer Unit; Well 1702-15DA WDW 01021 - Flaxman Island; Alaska State A - 2 010 22 - Redoubt Unit; RU D1 010 23 - Ivan River Unit; IRU 14-31 010 24 - Nicolai Creek Unit; NCU #5 DIO 25 - Sterling Unit; SU 43-9 010 26 - Kustatan Field; KFl Storage Injection Orders SIO 1 - Prudhoe Bay Unit, Point Mcintyre Field #6 SIO 2A- Swanson River Unit; KGSF #1 SIO 3 - Swanson River Unit; KGSF #2 Enhanced Recovery Inj ection Orders EIO 1 - Prudhoe Bay Unit; Prudhoe Bay Field, Schrader Bluff Formation Well V-105 2 2 2 2 2 2 3 3 3 3 No rule 3 3 No rule ') L. 2 No rule Affected Rules "Well Integrity Failure and Confinement" "Administrati ve Action" 3 4 3 5 3 6 3 5 3 Rule not numbered 3 5 3 6 4 6 4 6 4 7 No rule 6 No rule 6 Order exp ired 4 7 4 7 No rule No rule No rule 6 No rule 7 No rule 8 Injection Order EIO 2 - Redoubt Unit; RU-6 ) "Demonstration of 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 BOTT()M f'dRJNVOICE 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 AOGCC 333 West th Avenue, Suite 100 Anchorage, AK 99501 907-793-1221 AGENCY CONTACT DA TE OF A.O. R o M Jody Colombie September 77, 7004 PHONE PCN (907) 793 -] ??l DATES ADVERTISEMENT REQIJIRED: T o J oumal of Commerce 301 Arctic Slope Ave #350 Anchorage, AK 99518 October 3, 2004 THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: United states of America AFFIDAVIT OF PUBLICATION REMINDER State of ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMllTED 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 Public Notices ) ) Subject: Public Notices From: Jody Colombie <jody _ colombie@admin.state.ak.us> Date: Wed, 29 Sep 2004 13:01 :04 -0800 To: undisclosed-recipients:; BeC: Cynthia B Mciver <bren_mciver@~d:rrti~.state.ak.us>, Ang~laWebb . <angie _ webb@adtnin~s~ate.ak:.us>, Robert EMintz <robert_min.tz@law.state.ak.us>; Christine Hahsen.<c.hans~n@iogcc.state.ok.us>, Terrie·Hubble <hubble~l.@bp.com>, So~dra Stewman <StewmaSD@BP.com>, Scott·& Cammy Taylor <staylor@·ahlsk~.Ï1:et>, stailekj <sianekj@unoca1.co1n>, ecolaw <ecolaw@trustees.org>, roseragsdale ~roseragsda1e@gci.net>, trmjr 1 <trmjr 1 @aol.com>, jbriddle <jbriddle@marathonoiLcom::>, rockhil~. <rockhill@aoga.org>, shaneg <shaneg@evergreengâs.com>, jdarlington <jdarIington~f(J~estoil~com>, n~1son. <knelson@petroleumnews.com>, cboddy <cbQd4y@usibelli.com>, . Mark ,D.alton . <mark.dalton@hdrinc.com>,. Shannon Donnelly <shannon.donneUy@conocophiIlips.coI't1>:. "Mark P. . . , ,\. f: Worcester" <mårk.p~worcester@conocophillips.com>, "Jerry C. Dethlefs" ... ... ! . <jerry.c.dethlefs@conocophillips.com>, Bob <bob@inlet],(eeper.org>, ·wdv <wdv@dnr~statê.ak.us>, tjr <tjr@dnt~state. ak.us>, bbritch <bbritch@alaska.net>, J.1ljnelson <mjnelson@pu:rvingertz.çom>, Charles O'Donnell <charl~s.o'donnell@veco.com>, "Randy L. Skillern" <Skíl1eRL@BP.com>, "Deborah J. Jonestl <JonesD6@BP.com>, "Paul G. Hyatt" <hyattpg@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>" Lois <lois@inletkeeper~org>,Dan Bross <kUacnews@kuac.org>, Gordon Pospisil<PospisG@BP.com>, "Francis·S. Sormner" <SommerFS@Ì3P~com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GlÒverNW@BP.com>,."Dary:1 J.·K1eppin" <KleppiDE@BP .com>, "Janet D. Platt'~ <PlattJD@BP .com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <ddonkel@cfl.rr.com>, Collins Mount <collins _ mount@revenue.state.ak.us>, Mckay <:mckay@gci.net>,Barbara F Fullmer <barbara.f.fullmer@conocophillips.com>, bocastwf <bocastwf@bp.cpm>,. Charles Barker . <barket@usgs~gov>, doug_schultze <doug_ schultze@xtoeriergy..com>,Hank Alford .. <hank.alford@exxonm.øbiLcom>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower..com>,Gregg Nady <gregg.nady@shell.com>,Fred Steece <fted.steece@state.sd.us>, rcrotty <rcrotty@ch2m~com>, jejones <jejones@~tirorilpower.com>, dapa <dapa@alflska.net>,jroderick <jroderick@gcLnet>, eyancy <ëyancy@seal-tit~.net>, "James M. Ruud" <James.IÍl.ruud@conocophillips.com>, Brit Lively <map~aska@ak.net>, jab·· <jah@diJ.r.state.ak..us>, Kurt E Olson <kurt_olson@legis.st~te.ak.us>, buønoje <buonoje@bp.com>, Mark Hanley <mark_hanleY@at1adarko.com>, loren:-Ieman <loren_leman@gov.state.ak.us>, Julie Houle <julie_houle@dnr.state.ak.us>,. JohnW Katz <jwkatz@sso.org>, SuZanJ Hill <suzan_ hill@dec.state·.ak..us>, tablerk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak..us>, bpopp <bpopp@borough.kenaLalcus>, JimC~te <j·imwhite@satx.rr.com>, "John S. Hawórth" <jolm.s.haworth@exxo~obiLcoIi1>, marty <triâttY@rlô:ñâusmâILcom.>, ghammons <gham~ons@aol.colIl>,. rmclean <rmc1ean@pobox.alaska.net>, mkm7200 <mkm12~@ao1.coni>,·Brian Gillespie. <itbmg@uaa.alaska.edu>, David· L Boelens <dboelens@a~orapower.co:in>, T()dd Durkee <TDuRKEE@KMG.com>, Gary Schultz <gary _schultZ@dnr.~tate.ak.us>, .W~yne.Rancier <~~~~~~p~'f.ltj..canada.ca>, Bill Miller <Bill_ Miller@xtoalaska.cQm>, ·Br~~Qri Gagnon <b~~g11Q~~~r~~.lavv~com>, Paul Winslow <pmw4islow@forestoil.coin>, GmT)' Catron Sc~tB:1~~~t,p.~9~è' Sharmaine Copeland <copelasv@bp.com>, Suzanne Aliexan . <§~~~~~~Þ~~tR~µ~J!gy .com>, Kristin Difks ·<kristin _ dìrlci@c;Inr.state.åk.Us>,. KayIi~ll Zeman <rcj~~~åJi@Ìp~~fJlÓ1'loil.com>, John Tower <John.Tower@eía.dóe.gov>, Bill Fowler . <aill~FoWler@~adàrko.COM> , Vaughn Swartz <vaughn~swartZ@rbccm."Com> ,Scott Cranswick 10f2 9/29/2004 1: 10 PM Public Notices <scott.cranswick@mms.gpv>, Brad McKÏIn <rnckimbs@BP.com> ,~~e.~~r·..finc1· t¡h.e....a;t;:t~ch~.dNot ige.ª,ndÀttasl1Inent:fort~~J?!r8go~~ª. aménâineht \1:ì1ð.~rgrouIIð.inject:::ion orders· and the puhlic Notice HapPyVë1;lley #10. ~C)dy COlombie ..... ""'..."...............'".."""..,,,,,,.......,,..,.',,......,,..,,...... .. .'. . ...........................',.'... .............. .... ................. ........... '.. ............................ .. . ". ..... '. . : ....... ....... .... '. .,. .. ." ". .' . .... '.' . . '.' ...¡.CQ~tent-Type: £ipplication/rnsword ! il\11echanica'Integrityproposal.dqç:. ......... ............................. . ..... ···.······...i ·0' .' ···6··/t· . ;çQntent~Encøªmg.:.. .... .ase ". ..~ -..---. .--- ". ~...._...__...... ..... .................... ...... .. . ..··.·.···1·······.··.· ... ..... .' ................................'>./.. .... .. ". '.. '.. ...... '.) ..,......,. ......... ......, '>,. .' '.'. ..... .... .. ....... ........ '.1 (Jontent7"'Eyp~: applicatÌow11lS,¥otd Me.chaolcalIntegrIty of WeIlsNobce~doc: .... '.' '.' .,.......'.... ............. ...... ... "'b" . ·6'4'. . ! Content-En~()ªing: ··ase : Content-Type: aþplication!tnswotd .IIappyVaUeyl0_HearingNotice.doc, ............. ...< ...... . i Cøntent-EncQ~g:hase64 ~_ Mm.,,,..~, ~_.",..'....~.. _, .__.~."_.,_~_._.'._._,.'~... ~'..... .._.,,~'~'. """"'....." .,' ~ .~.~"""'_'" .". . .,,_u.'_... "'. .'...... '... __ ...:."..,_.. ''''_'_''_..._ ~'. ..., .. ._"., ~_"U·_"'."__"._"'_'. .___,,__,'_~~.. ""'__''''~-'.'__'''_~''___~'' _ .,....,__..'~",. ...~. ".,....," _._~ ,..._.. 20f2 9/29/2004 1: 10 PM Public Notice ) ') Subject: Public Notice From: Jody Colombie <jody_colombie@admin.state.ak.us> ~~!e:....."Yecl,<2?..~.e~...~.~..~.~.. .1?:~5.:26 -0800 19~::.l~g~!'c&~!~i(å;jp~~~Cºtµ··· . Please publish the attached Notice on October 3/ 2004. Thank you. Jody Colombie Content-Type: applicationimsword Mechanical Integrity of Wells Notice.doc: b 64 i Content-Encoding: ase ."........ .. ..",..""..""..,.... Content-Type: applicationimsword : 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 /'1a¡/¿:d /tJ/¡(t~ 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 1 3557 Denver, CO 80201-3557 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise,lD 83702 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St. Ste 200 Seattle, WA 98119-3960 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 James Gibbs PO Box 1597 Soldotna, AK 99669 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 North Slope Borough PO Box 69 Barrow, AK 99723 (Fwd: Re: Consistent Wording for Injection þrs - Well Integrity... ) ~ubject:. [Fwd: Re:. ·Consistent Wörgiv~f9t ~j~~tio~....Ordêfs ~··.Wêll··lp;~~'~irY{R~vi$eg)] Ff0In:. John Norman<.i?hn~ nOrman(@a9min~state.ctk.us> ~i~~~~ '. F~~~..?I...,,<?ct.. ?~?1T..~,. :?9:~6.-9~-o? '.........'..... ...,..,.. ....' '.. ..'............ ... ..... .......,.......................... 1'~;:<J"()gy J...ÇpIg~þ~~....<fj.ogyi:þ(:)~QD;11Irie@~~i~.:stélt~~a}pµŠ? .. 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 11lintz@law.state.ak.us> To:jim regg@admin.state.ak.us CC:dan seamount@admin.state.ak.us, john norman@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 Commission." 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 <¡im 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 <¡im 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 1 of 2 10/2/20044:07 PM [Fwd: Re: Consistent Wording for Injection ~rs - 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 sluny 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 OIOs 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 oftenns 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 JohnK. Norman <John Norman@admin.state.us> Commissioner : Alaska Oil & Gas Conservation Commission 20f2 10/2/2004 4:07 PM (Fwd: Re: Consistent Wording for Injection ~rs - Well Integrity... ) ~tibject: [Fwd: Re:ConsistentW ordingJor Injection Orqen; ~WenIntégrity(ReyiSed)] F'roItl: John Nonnan <jQhn~norman@admin~state.ak.µ.s> D.........,.:...,a... :..,t.............e......, : F..': r.:...i, 0.1. .. .0. .. .....c:..'.t..... 2. ,...0........9.".,..4 11 :08: 5 5 -0800 I9£}è>ØY .JCgJºl)]qi,~<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 re,gg@admin.state.ak.us, john nOffilan@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 red lines on the second document attached. »> James Regg <jim regg@2admin.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 Sf. 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 l\'lechanical 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 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 10f2 10/2/2004 4:07 PM [Fwd: Re: Consistent Wording for Injection ;rs - 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 oftenns 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 JohnK. Norman <John Norman@admin.state.us> Commissioner ¡ Alaska Oil & Gas Conservation Commission Content-Type: applicationlmsword Injection Order language - questions.doc Content-Encoding: base64 Content-Type: applicationlmsword Injection Orders language edits. doc Content-Encoding: base64 20f2 10/2/2004 4:07 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 Form 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 two years in the case of a slurry injection well), and before returning a well to service fol1owing afte.F a workover affecting mechanical integrity, and at ka~;t once every 4 years while actively injecting. For :;!urry injection wells, the tubing/casing annulus lnust be tðsted for mechanical integrity every-;&-y·e·ars-:· Unless an alternate GleanS is approved by the Cornnlission. lnechanìcal integrity iTIUst be dClTIOnstrated by a tubin.Q: pressure test using a ::çfle MfF-surface pressure of must be 1500 psi or 0.25 psi/ft multiplied by the vertical depth, whichever is greater, that ffiH-St-show3. stabilizing pressure that doesand lnay not change more than 10Q.:ö- percent during a 30 minute period. --Afl.y altenlate nlcans of dCtTIonstrating Inechanical integrity l1IUSt be approved by the COlnn1ission. The Commission must be notified at least 24 hours in advance to enable a representative to witness pressure tests. Well Integrity Failure and Confinement Except as otherwise provided in this rule, +1he tubing, casing and packer of an injection well must Ekffiorr~~trate lnaintain integrity during operation. \Vhenever any pressure con1ffiunication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log. or other evidence, t+he operatorffi:B-St-shall immediately notify the Commission and submit a plan of corrective action on a Form 10-403 for Commission approval.: v,,-henever any pressure C01TIlnUnication, leakage or lack of injection zone isolation .is indicated by injection rate, operating pressure ob$ervation, test, survey. or log. The operator shall shut in the well if so directed by the COi1unission. The operator shall shut in the well without a\vaiting a response tì-om the COlTllnissÎo!l if continued operation \\iould be unsafe or would threaten contamination of freshwaterIf there is no threat to freslnvater, injection lnay continue until the COl111nìssion requires the \vell to be shut in or secured. Until corrective action is successfully cotnplctcd, Aª 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 willnot result in fluid movement outside of the authorized injection zone. · '[Fwd: Re: [Fwd: AOGCC Proposed WI Lal ,þe for Injectors]] ) $1J.~;.ect: [Fwd: Re: [Fwd: AOGCCProposed WI Language for Injectors]] 1f~():IR:.WintonAubert ·<winton_aubert@admitl.state.alcus> ~~I~~~~~~t~tl~~Ui~~~.~l~.. This is part of the record for the Nov. 4 hearing. WGA -------- Original Message -------- Subject: Re: [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 <EngelHR@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 I 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 Lang for Injectors]] return5_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 injection rates must be provided to the Commission for all injection wells indicating well integrity failure or lack of injection zone 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 lack 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, Daryl J Sent: Wednesday, September 29, 2004 1:37 PM To: Townsend, Monte Ai Digert, Scott Ai Denis, John R (ANC) i 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 #10 ) ) PIIILU'PS .œ PHilliPS Alaska, Inc. A Subsidiary of PHILLIPS PETROLEUM COMPANY To: Robert Crandall Wayne Campaign Meltwater North Aquifer Exemption July 18, 2001 RECEIVED JUL 2 6 2001 From: Subject: Alaska Oil & Gas CO'ns. Commlsslm Anchorage - This document will present the interpretations that support the absence of fresh water aquifers in the area of the Meltwater development. Date: For the purpose of this document, Aquifer is defined as sand that has a reasonable expectation of producing fluids. From North slope experience, I have defined Sands (aquifers) as having effective porosity> 18% and shale content < 40%. Fresh Water Aquifer is an aquifer that contains water of salinity less than 10 Kppm TDS and no hydrocarbons. Shallow logs were acquired in three nearby wells; 2N-349 (Tarn) Wireline Neutron/Density/Dipole Sonic/Resistivity/GR Cirque 2 (Exploration) Wireline Neutron/Density/Dipole Sonic/Resistivity/GR, Mudlog 2P-438 (Meltwater) LWD Neutron/Density/Resistivity/GR, Mudlog Shallow intervals in these wells were evaluated for shale volume, total and effective porosity. Total porosity and true resistivity were combined to calculate apparent water resistivity utilizing the techniques from the EPA documentation ("RP" or RWapparent), as outlined in previous correspondence. This was combined with fonnation temperature to calculate water salinity in Kppm of Total Dissolved Solids. Sands were identified using the above criteria and results for the 3 wells are presented in the attachments. The attachments are log plots graduated in Subsea depth. The first track is a lithology column with volumetric representations of shale, sand and effective porosity. Depth tracks are next. For the Cirque and 2P-438, the next log track is the Total Gas (in Units) from the Mudlog. Then fonnation resisti vity and TDS curves are displayed on a logrithmic grid. The TDS curve is highlighted in dark blue within the sands as defined above. The last tracks are plots of the common gas indicator logs available. Plotted curves are the Neutron and Density curves in one track. Free gas is indicated by close approach or crossover of the curves, which is coded red. 2P-438 is the best example of this. When available, the Dipole sonic curves are plotted in the final track. Compressional and shear curves are normalized in the shales. Free gas is indicated when the compressional delta t shifts left relative to the shear value. These intervals of curve separation are also coded red. The presentations indicate that virtually all of the Sands defined in this shallow interval contain gas in one fonn or another. Indications are that the logs are measuring free gas and not hydrates specifically. This is due to the fact that wireline logs are run long after the zones are drilled. Warmth from the drilling process probably have thawed any hydrates in the near-wellbore region, leaving free gas to be detected by the logs at wireline time. Phillips Alaska, Inc. is a Subsidiary of Phillips Petroleum Company ) Mr. Wayne Campaign July 26, 2001 Page 2 From the evidence in these logs, I conclude that there are no likely fresh water aquifers within the Meltwater Area, as represented by this dataset. If you have questions, comments or discussion, feel free to contact me. Wayne Campaign Petrophysicist, Phillips Alaska, Inc. () ,Qíì - .var( .- ldJ~ Phillips Alaska, Inc. Is a Subsidiary of Phillips Petroleum Company #9 ") ) PHilliPS Alaska, Inc. A Subsidiary of PHilLIPS PETROLEUM COMPANY Post Office Box 1 00360 700 G Street Anchorage, Alaska 99510 Telephone 907 265-6806 RIECEi\fE ,i 2001 Ryan Stramp, Meltwater Coordinator ,Maska Oil (~ Gas COns. Commission June 6, 2001 Ms. Julie Heusser, Mr. Dan Seamount and Ms. Cammy Taylor Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Re: Meltwater Aquifer Exemption Dear Commissioners: By this letter, Phillips Alaska, Inc. (PAl) is seeking an Aquifer Exemption for the Meltwater Injection. In accordance with 40 CFR 144.7, the Meltwater Injection Area meets the criteria for an "exempted aquifer". a) There are no aquifers that currently serve as a source of drinking water in the region. b) There are no aquifers that will serve as a source of drinking water in the future. First, many of the aquifers in the region contain hydrocarbon accumulations (i.e., gas and/or gas hydrates) that may be commercially producible in the future. Second, the aquifers are situated at a depth (> 1500') and location (i.e., the North Slope of Alaska) that makes recovery of water for drinking purposes economically impractical. c) The total dissolved solids content of the ground water is more than 3,000 mg/I, and it is not reasonably expected to supply a public water system. The following attachments are submitted in support of a Meltwater Aquifer Exemption: 1. Meltwater accumulations and associated injection area. 2. Meltwater Injection Area relative to regional aquifers exemptions. 3. Log salinity calculation summary for wells in the vicinity of the Meltwater Injection Area. 4. Meltwater 2P-438 and Cirque #2 shallow log results with mud log data showing shallow gas and/or gas hydrates. 5. Crossplots of Rwa versus depth for Meltwater 2P-438 and Cirque #2. Phillips Alaska, Inc. is a subsidiary of Phillips Petroleum Company ') ') I appreciate your work on the Meltwater Aquifer Exemption application and would be happy to answer any related questions. I can be reached at 265-6268 or rstramp@ ppco.com via email. Sincerely, ~~, ~n Stramp Meltwater Coordinator - Meltwater Aquifer Exemption Application Page 2/11 Attachment 1 Meltwater Accumulations & Injection Area 10-31-05 Meltwater Injection Area 01030104C01 Meltwater Aquifer Exemption Application Page 3/11 Attachment 2 Meltwater Injection Area Relative to Regional Aquifer Exemption AlpineAquifer Exemption Kuukpik Kalubik 1 e Star Milne Point Riv3 Kuparuk River Prudhoe Alpine Pool Sections 2N-349 e 2 Greater Kuparuk Aquifer Exemption N2 Meltwater Meltwater Aquifer Exemption Application Page 4/11 Attachment 3 Log Salinity Calculation Summary Analysis of all available data indicates there are no potential aquifers with total dissolved solids <3000 ppm. In addition, log data suggests that shallow intervals conatin gas and/or hydrates. No porosity logs were acquired in the surface hole (above approximately 1900' tvd subsea) of the Meltwater exploratory wells. However, shallow logs were acquired on Meltwater development well 2P-438. Wells in the general vicinity of the Meltwater Injection Area (i.e., Kalubik #1, Colville River St. #1, Cirque #2 and 2N-349, which were previously shown on Attachment 2) were analyzed for fresh water acquifers using the SP Technique and the Rwapparent Technique. (The Rwapparent Technique is referred to as the Resistivity- Prosity Technique, or "RP", in EPA literature.) Both are well known techniques within the industry. Discussion is provided below on the limitations of each method and the associated salinity estimates. Two of the four wells (Kalubik #1 and Colville River St. 1 ) are outside the existing KRU and Alpine Aquifer Exemption Areas. The other two welsl (Cirque #2 and 2N-349) are located within the KRU Aquifer Exemption Area. The following table is a list of salinity calculations for the sand underneath the permafrost. Calculated fluid resistivities are corrected to 750 F and salinity numbers are in NaCl equivalent, or total dissolved solids (TDS). Meltwater Aquifer Exemption Application Page 5/11 Kalubik #1 Colville River St #1 Cirque #2 2N-349 Rmf = 1.19 Q-m @ 69' Rmf = 2.52 Q-m @ 68' Rmf = 2.28 K2-m @ 85' Rmf = 3.3 Q-m @ 63' Permafrost @ 1510' Permafrost @ 1360' Permafrost @ 1 t70' Permafrost @ 1310' Sand @ 1740'-90' Sand @ 1510'-20' Sand @ 1440'-60' Sand @ t905'-15' (D=36 Rt=12f2m (D=36 Rt=2.1Qm (D=34 Rt=260m 0=31 Rt=10f2m Rwa = 1.09 Om Rwa = 0.24 Qm Rwa = 2.1 Orn Rwa = 0.8 Orn (5.3 Kppm) (28 Kppm) (2.5 Kppm) (6.9 Kppm) SP = -35 my (@ 350) SP = -40 my (@ 340) SP = -20 my (@ 35°) SP = -20 my (@ RwSP = 0.38 Sim RwSP = 0.5 Orn RwSP = 1.03 Orn 440) (15 Kppm) (20 Kppm) (5.4 Kppm) RwSP = 1.19 f2m (4.5 Kppm) Hole badly washed Zone slightly shaley. Hydrates known .SP Hydrates below out. SP probably Salinities quite high. more representative Permafrost. Rwa more representative. though still too low. more representative. Best TDS Estimate = Best TDS Estimate = Best TDS Estimate = Best TDS Estimate = 10 - 12 Kppm —20 Kppm >5.4 Kppm >6.9 Kppm In the Kalubik #1 and Cirque #2 wells, average resistivities drop dramatically below these sands, indicating much saltier waters. In the Colville Rive St. #1 well, the high salinities begin at the base of permafrost. 2N-349 Base Permafrost picked at 1310' with the section below interpreted to be hydrate bearing. This is supported by mud log results from Meltwater 2P-438 (see Attachment 4). Shale resistivities suggest salinities in the 6-10 kppm range. Rwa in the sand at 1910' calculates TDS of 6.9 kppm. This section of the well has wireline logs to 2330' with LWD below that. LWD resistivity decreases systematically below 2400', implying an increase in salinity below that depth. There are no appreciable sands present below in which to verify this salinity, though estimates from the shales would suggest salinities of 20+ kppm TDS. Kalubik #1 Water salinities below permafrost are estimated to be in the 10-12 Kppm range (TDS), increasing to 25 Kppm below 1950'. An analysis of a water sample from Albian aged sands (5050-5250') in this well tested 24.3 Kppm TDS. Meltwater Aquifer Exemption Application Page 6/11 . . Colville River St. #1 Salinities below permafrost are approximately 25 Kppm TDS. Cirque #2 Under permafrost, salinities are 6+ Kppm increasing to 21 Kppm below 2200'. The sand immediately below the permafrost is believed to contain gas and/or gas hydrates, which causes log based salinity calculation results to be too low. This is supported by mud log results shown in Attachment 4. Attachment 5 is a plot of Rwa versus depth for the shallow portion of this well. 2P-438 Meltwater 2P-438 salinity calculation results are not shown in the summary table. All salinity calculations below the permafrost are affected by presence of gas and/or hydrates. Apparent salinities in the shales, however, are in the range of 6+ kppm. Calculated salinities shift to an average value of 10 Kppm below a depth of 2200', though there are no sands present for confirmation. Attachment 5 is a plot of Rwa versus depth for the shallow portion of this well. None of the wells exhibit decreased salinity below these depths. Meltwater Aquifer Exemption Application Page 7/11 Attachment 4 Shallow Log Results for 2p..438 LWD.RD 1 Meltwater Aquifer Exemption Application Page 8/11 Attachment 4 (Continued) Shallow Log Results for Cirque #2 Meltwater Aquifer Exemption Application w o z a: « f- I if! D- C f- ~I >- « D- u U ..J D- X ill Page 9/11 1000 1300 1600 - tu 1900 W I.L - 2200 J: t- B:i 2500 C ~ 2800 fJ) .c :J en 31 00 3400 3700 4000 !.t) ,.... 0 0 0 0 þ Attachment 5 R A I DEPTH Crossplot Well: 2P-438 1000.0 - 4000.0 FEET Filter: RH08<2.22 o ,.... o ,.... RWA@75 (OHMM) Color: VSH Meltwater Aquifer Exemption Application Page 10/11 þ Attachment 5 (Continued) R A I DEPTH Crossplot Well: Cirque 2 1000.0 - 4000.0 FEET Filter: RH08<2.42 1600 Hydrates c::::» c::::» c::::» .. 1000 Base Permafrost 1300 1900 - t- W 2200 W I.L - J: 2500 t- n. 2800 (\I") 3100 3400 3700 4000 ,.... o Lti RWA@75 (OHM o Color: VSH Meltwater Aquifer Exemption Application Page 11/11 #8 A A TONY KNOWLES, GOVERNOR A14"KA OIL A" GAS 333 W. T" AVENUE, SUITE 100 CONSERVATION COM11'IISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 May 23, 2001 Mr. Ryan Stramp Meltwater Coordinator Phillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Meltwater Pool Rules & Area Injection Order Dear Mr. Stramp: We are writing to follow through on a couple of unresolved issues related to the Meltwater Pool Rules and Area Injection Order. The first issue is whether PAI needs to have an aquifer exemption to conduct the proposed enhanced recovery operation in the Meltwater Pool. Although the proposed Meltwater Pool area lies outside the Kuparuk River Unit area and is not subject to the existing KRU aquifer exemption for Class II underground injection, PAI's application for an AIO seeks only authorization to conduct an enhanced recovery operation in a proposed injection zone that has no freshwater. PAI has demonstrated that the proposed enhanced recovery operations will not allow movement of fluid into sources of freshwater. Therefore, PAI does not need to secure an aquifer exemption in order to conduct this enhanced recovery operation. However, should PAI have other reasons to request an aquifer exemption for the Meltwater Pool area, the application requirements can be found at 20 AAC 25.440. You may wish to keep in mind for future planning purposes that the Commission may grant underground injection control variances when injection does not occur into, through or above freshwater. See 20 AAC 25.450. The second issue is the subject of waste disposal for the Meltwater development. Although PAI's application does not include a Class II disposal well, PAI acknowledges it may need one in the future. The Pool Rules testimony indicates that annular disposal of drilling wastes will be utilized in accordance with 20 AAC 25.080. Although there is mention of waste fluid being transported to a permitted disposal facility, we would like to point out that annular disposal may not be used to circumvent the requirements of 20 AAC 25.252 relating to underground disposal of oil field wastes. Similarly, approval to conduct annular disposal operations requires a thorough discussion of many factors, ¡ ) ) Meltwater Pool Rules & Area Injection Order May 23, 2001 Page 2 of2 including confining zones, fracture information, injection zone lithology and freshwater analyses of potential injection zones. If you have any further questions or comments please feel free to contact either Bob Crandall or Wendy Mahan at the above number. They would be happy to assist you. Sincerely, ~j+G Cammy hylor Chair CT\jjc #7 '-') -- 1 2 3 4 In Re: "') ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING 5 CONSIDER APPLICATION FROM PHILLIPS ALASKA, INCORPORATED, TO ESTABLISH POOL 6 RULES FOR THE MELTWATER OIL POOL WITHIN THE KUPARUK RIVER FIELD, AND TO 7 APPROVE THE AREA INJECTION ORDER AUTHORI·ZING ENHANCED OIL RECOVERY 8 OPERATIONS IN THE POOL. 9 TRANSCRIPT OF PROCEEDINGS 10 11 12 13 APPEARANCES: . 14 Commissioners: 15 16 17 18 19 20 21 22 23 24 25 Anchorage, Alaska May 7, 2001 9:06 o'clock a.m. MR. DANIEL T. SEAMOUNT, JR. MS. CAMMY OECHSLI TAYLOR MS. JULIE HEUSSER * * * * * * ~~c "t'o%1 o/4J- ~V.t-. ~~q)cf .¡ .¡ '() -i'~.r ~ <'00/ ~~ ~ CQ i9 0~. v.s-.£. ~ - MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · · · () () 1 PRO C E E DIN G S 2 (On record 9:06 a.m.) 3 COMMISSIONER SEAMOUNT: I would like to call 4 this hearing to order. The date is Monday, May 7, 2001. The 5 time is 9:06 a.m. Location is 333 West Seventh Avenue, 6 Anchorage, Alaska. It's the offices of the AOGCC. I'll start 7 by introducing the bench. My name is Dan Seamount. To my 8 right is Cammy Taylor, and to my left is Julie Heusser. We're 9 the three Commissioners of the AOGCC. Sharon Gaunt of Metro 10 Court Reporting is making a transcript of the proceedings. You 11 can get a copy from Metro Court Reporting. 12 The purpose of this hearing today is to consider an 13 application from Phillips Alaska, Incorporated, to establish 14 pool rules for the meltwater oil pool within the Kuparuk River 15 Field, and to approve the area injection -- an area injection 16 order authorizing enhanced oil recovery operations in the pool. 17 Notice of the hearing was published on March 23, 2001, 18 and an amended notice was published on AprilS, 2001. 19 Proceedings are held in accordance with 20 AAC 25.540. Those 20 are the regulations governing public hearings. The hearing 21 will be recorded. Is that correct? Okay. Sorry fo~ 'calling 22 you at such late notice. 23 COURT REPORTER: It's okay. 24 COMMISSIONER SEAMOUNT: No off the record 25 conversation except among the Applicants themselves during MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 3 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. 23 providing the initial testimony. Do you want us to introduce 24 ourselves all at once now, or just as we enter into our 25 testimony? 22 themselves and approach the Commission. I'll be the So, we would like to invite the Applicant to introduce 21 20 today, so I may forget something. Okay. 19 We don't have our assistant attorney general helping me out 18 Commissioners. So, I guess anything to say introductory-wise? 17 wishing to cross examine will be considered by the 16 other testimony such as protest or cross examination. Those 15 then the Commission will ask the question. We'll also allow 14 to write the questions, forward them up to the bench here, and 13 have other interested parties, the way to ask the question is . COMMISSIONER SEAMOUNT: Okay. Well, if we do 12 11 took it. UNIDENTIFIED MALE SPEAKER: Somebody -- Jody 10 9 sign in sheet. Where is the sign in sheet? 8 there other interested parties in here today? I didn't see a 7 opportunity for other interested parties to ask questions. Are 6 expert. We'll hear from the Applicant first. Then we'll allow 5 and the Commission will rule whether to consider you as an 4 be considered an expert, you must state your qualifications, If you wish to 3 statements. We give greater weight to sworn. we consider sworn testimony or unsworn 2 provide that We 1 recess or in camera which will be a confidential session. . l) () . ) .' ) It 1 COMMISSIONER SEAMOUNT: I think probably as we 2 enter into the testimony would be appropriate. 3 MR. STRAMP: Okay. 4 COMMISSIONER SEAMOUNT: So, your name is? 5 MR. STRAMP: Okay. 6 COMMISSIONER SEAMOUNT: First of all, are you 7 giving sworn testimony? 8 MR. STRAMP: Yes. Yes, sir, I am. 9 10 hand. 11 12 13 e 14 COMMISSIONER SEAMOUNT: Okay. Raise your right (Oath administered) MR. STRAMP: Yes, I do. COMMISSIONER SEAMOUNT: Please state your name. MR. STRAMP: My name is Ryan Stramp, and since 15 I will be giving sworn testimony, I would like to briefly state 16 my qualifications. I graduated from the University of Oklahoma 17 with a degree in petroleum engineering in 1977. Upon 18 graduation, I went to work for Arco working on the Permian 19 Basin on fields in West Texas and New Mexico. In 1981, I was 20 transferred to Alaska still with Arco, and have resided in 21 Alaska working on Alaska oil fields since then. In almost 22 twenty-four years of working in the oil industry, initially, 23 with Arco and now with Phillips, I've held a variety of 24 engineering and operations assignments including stints as a 25 reservoir engineer, production engineer, on site production . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 4 . . . . ) . 1 supervision, and most recently for the past several years, my 2 work experience has focused on planning and executing field 3 development projects in and around the Kuparuk Field. One very 4 noteworthy project that you'll hear some references to today 5 that I was very involved in was the Tarn development project. 6 And for about the past year or ever since the meltwater project 7 has been in exi~tence, I've been the project coordinator for 8 that project. 9 COMMISSIONER SEAMOUNT: Do any of the other 10 Commissioners have questions concerning Mr. Stamp's 11 qualifications? 12 COMMISSIONER TAYLOR: I don't. 13 COMMISSIONER HEUSSER: No. 14 COMMISSIONER SEAMOUNT: Okay. Mr. Stramp, 15 you'.re accepted as an expert witness. 16 MR. STRAMP: Thank you. Before we get into the 17 main body of the presentation, I wanted to offer a few 18 introductory comments. As you probably know, just over a year 19 ago, Phillips Alaska announced the discovery of the Meltwater 20 Field, and we're here this morning to present testimony to 21 support classification of this Meltwater reservoir as a new oil' 22 pool, and to request pool rules be formally put in place for 23 that new pool. 24 Phillips Alaska has been designated the operator for 25 the Meltwater development on behalf of the other Meltwater MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 5 6 745 West Fourth Avelzue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. 25 II comments, then Steve Moothart will provide some geologic 24 II of our agenda for today. I'll continue with my introductory 23 II number two in the lower left-hand corner. This is an outline MR. STRAMP: Yes. You'll find the slide with 22 COMMISSIONER SEAMOUNT: This one. 21 20 II the pool rule testimony. MR. STRAMP: Okay. They're the ones that say I've got..... . 14 15 slides today? 16 17 18 would they be? 19 COMMISSIONER SEAMOUNT: Okay. Which slides MR. STRAMP: Yeah. They..... COMMISSIONER SEAMOUNT: You delivered some 13 II slides in front of you there that you can follow along on? 12 II put up the agenda, if you would. Do you have copies of the Put up the first slide, (indiscernible). Go ahead and 11 10 II public record in support of our requests. 911 the summary presentation also be considered as part ,of the 8 II request that the slides that we will be presenting today and 7 II testimony with the Commission. In addition, we would like to 6 II area injection order, and have filed updated copies of that 5 II testimony with the Commission for both the pool rules and the . 1 owners. In the discussion this morning, we will provide 2 testimony on the geological and reservoir properties as we 3 II currently understand them for Mel twater, and along with our 4 II plans for development of the field. We have prefiled written .) 6) II . . .) .) 1 insights into the Meltwater Pool. Lamont Frazer will talk 2 about some reservoir and operations and hearing issues. Tom 3 Brockway will discuss some billing and completion items, then 4 I'll take the podium again and close by summarizing some issues 5 related to our surface facilities, and then an overall summary 6 of the testimony. 7 Slide three in the packet is just a regional map of the 8 North Slope to orient you with where Meltwater is. You can see 9 it's on the southwest corner of the what we call the Greater 10 Kuparuk Area, about ten miles south of the Tarn Field. It's 11 about twenty-five miles from Meltwater back to CPF2, and we're 12 about seventeen miles from the Village of Nuiqsut. 13 Slide four provides a little bit of background 14 information on the exploration activities that were taking 15 place about a year ago at Meltwater. In early 2000, we 16 obtained three penetrations into the Meltwater Reservoir, and 17 had the subsequent discovery announced. These were two stand 18 alone wells plus one side track. The green 'dots here on the 19 map represent the penetrations. On the right-hand side of the 20 slide here is a plot of the well test information from the one 21 penetration that we did test showing that the Meltwat~r North 22 Number 1 well tested at a peak rate of approximately 4,000 23 barrels a day and then fell off slightly after that with GORs 24 initially about 500, increasing to about 700 standard cubic 25 feet per barrel. MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 7 tit . . e· ), . ) 1 The next slide provides a very brief overview of the 2 Meltwater project as we know it now. One of the key points is 3 that this is going to be another satellite to the Kuparuk Field 4 that will share the infrastructure, such as the processing 5 facilities and injection facilities that exist in that field. 6 The actual scope of the development of the project is a single 7 drill site with approximately twenty-six wells, and the 8 infrastructure that I referred to here are things like the 9 production flow line and the injection flow line and the road 10 and the power lines that are necessary to tie Meltwater into 11 the existing infrastructure in the Greater Kuparuk area. 12 We're targeting to have production on line later this 13 year. This will be an EOR project, enhanced oil recovery 14 project, from the very start. As you'll hear more about later, 15 our recovery process will be implemented as MWAG or miscible 16 water alternating gas, and our expected reserves using that 17 process are 18 recovery. 19 This approximately fifty-two million barrels of oil slide discusses the status of the project as of 20 today. We began construction activities on the Slope in 21 January this year. I'm happy to say that as of now, basically, 22 all of the other -- all of the other on tundra construction 23 work such as installation of the flow lines and the gravel road 24 and the powerline are now complete. And, in fact, we actually 25 have a drilling rig on the pad drilling the very first MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 8 . 13 . 14 15 16 17 18 19 20 21 22 23 24 . .) .) 1 development well right now as we speak. We also have the 2 construction work underway on pad to install the construct- 3 or the drill site facilities on pad, and those activities will 4 be ongoing until approximately on or before October 1st we hope 5 to have everything in place to be ready to begin production. 6 Slide seven discusses some issues related to the Unit 7 and PA status for Meltwater. We've had several discussions 8 with the Alaska Department of Natural Resources regarding these 9 issues. Our plans are to expand the existing Kuparuk River 10 Unit to include all of the lands that we envision associated 11 with the Meltwater development, and also form a new Meltwater 12 participating area. We'll be filing the applications requesting those actions to take place this week. And in that packet of information will be our formal plan of development and operations and exploration, and we will copy the Oil and Gas Commission on that application. Page eight is a map of the area that shows three different outlines that we feel are pertinent to consider. The outline and the solid black line is the area that we are asking to be included or the Kuparuk River Unit to be expanded to include -- the current southern boundary of the Kuparµk River Unit runs right along this line, and we are asking to add these two additional leases to the Kuparuk River Unit. The dashed line that I'm outlining here is the area 25 that we're requesting to be included in the initial Meltwater MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 9 · · · . :') ) . 1 participating area, and the contoured outlines on the map 2 represent our current net sand map for the Bermuda sand 3 accumulation in the Meltwater Reservoir. There's one other 4 outline that's kind of difficult to see, but the kind of 5 purplish outline on the slide illustrates the area that we'll 6 be talking about more today. This is the area that we're 7 requesting be included in the definition of the Meltwater Pool, 8 and also the area that the Meltwater area injection order would 9 apply to. 10 Slide nine lists the ownership percentages of the 11 companies owning rights to the oil accumulation. These 12 percentages are· a function of the leasehold ownership of the 13 leases involved in the participating area, and the relative 14 amount of net sand that we have mapped on each one of those 15 leases. This is similar but not exactly the same as the 16 satellite ownership in the rest of the Greater Kuparuk area due 17 to some minor differences in the leasehold ownership in this 18 area, but these ownership decimals have been agreed to amongst 19 the parties, and do represent the equity agreement for 20 Meltwater. 21 COMMISSIONER SEAMOUNT: Is that over all four 22 sections then, those percentages? 23 MR. STRAMP: Let me back up to the map. It 24 will -- I think we're upside down there. It's kind of hard to 25 do backwards. It applies specifically to the participating MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 10 .\ . · 1 area, and it was derived by calculating the relative amount of 2 net sand on the southern lease here and the northern lease and 3 the ownership of those leases. If the participating area were 4 expanded in the future, those decimals possibly would change, 5 but as far as the initial operations in a specific 6 participating area, those are the equity decimals. 7 As we move through the testimony this morning, we will 8 be providing not only some background information for the 9 Commission and the Commissioners but also suggesting some pool 10 rules. I wanted to list these four items as kind of the 11 guidepost that we use as we were coming up with the recommended 12 language. It should look pretty familiar to the Commission. 13 You know, certainly, we're interested as you are in preventing · 14 waste and promoting conservation and protecting correlative 15 rights, promoting maximum ultimate recovery from the field, and 16 you also see that we've tried to keep things consistent with 17 the pool rules in the immediate area including the Kuparuk, PA, 18 West Sag, Tarn, and other North Slope pools. 19 So, that concludes my portion of the testimony for 20 right now. I would like to turn it over to Steve Moothart next 21 to begin the geological discussion. 22 COMMISSIONER SEAMOUNT: Okay. Would you wish 23 to be considered an expert witness? 24 MR. MOOTHART: Yes. 25 COMMISSIONER SEAMOUNT: Raise your right hand, · MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 11 . . . . l )' . 1 please. 2 (Oath administered) 3 MR. MOOTHART: Yes, I do. 4 COMMISSIONER SEAMOUNT: Please state your name, 5 who you represent, what your qualifications are. 6 MR. MOOTHART: My name is Steve Moothart. I'm 7 a staff geologist with Phillips Alaska. Qualifications, I 8 graduated with my BS in geology from Oregon State University in 9 1986. Did independent contract work after that upon 10 receiving -- until receiving my masters in geology from Oregon 11 State University in 1992. I was hired by Arco Alaska in 1991. 12 Since that time, I've worked in Alaska up here working the 13 Kuparuk River Field as development geologist, and then also 14 working the developments of Tabasco and Tarn Fields. For the 15 past year, been working the Meltwater development plan. 16 COMMISSIONER SEAMOUNT: Do any of the 17 Commissioners have any questions regarding Mr. Moothart's 18 qualifications? 19 COMMISSIONER TAYLOR: I don't, thank you. COMMISSIONER HEUSSER: No. COMMISSIONER SEAMOUNT: Okay. Mr. Moothart, 20 21 22 you are being accepted as an expert witness. 23 MR. STRAMP: Can I visit with Mr. Moothart for 24 just a second? 25 (Side conversation) MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 12 . 1 2 3 4 5 6 7 8 . . . '~ . MR. MOOTHART: Brian just wanted to make a point that within my presentation there is a point where we'll be calling a confidential session, and we'll flag it, and at that point, we would like to present to you confidential session. COMMISSIONER SEAMOUNT: Okay. Just let us know when you get to that point. MR. MOOTHART: Okay. My first slide is -- 9 basically, it's the type log that we'll be using in talking 10 about for the Meltwater accumulation. It's the log of 11 Meltwater North Number 2A. From this slide, I want to discuss 12 the vertical definition of the Meltwater Pool. The Meltwater 13 Pool as we're defining it is a sequence of reservoir sandstones 14 and associated mud stones that are located between depths of 15 4,958. These are subsea tvd depths, and 5,297 subsea within 16 this Meltwater North A or 2Awell, and its offset equivalents. 17 This interval is Late Cretaceous in age, Cenomanian-Turonian 18 within the CB formation. It's approximately 350 feet thick, 19 and it's comprised of two genetically distinct and separate 20 intervals. And I'll discuss those now in descending 21 stratigraphic order. 22 First interval is the Cairn Interval. This is located 23 between the T4.1 and T3 correlatable markers. The -- in this 24 particular well, reservoir quality sands were not encountered 25 within the Cairn Interval, but we think that we do have MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 13 . ).. ') . · 1 reservoir quality sands in a lateral location. The Bermuda 2 Interval located between the markers T3 and T2, these were the 3 hydrocarbon bearing sands in this well, and then also in the 9 10 11 12 13 · 14 15 16 · 4 two offset wells, and then these are this was the interval 5 that's tested in the Meltwater North Number 1 well that Ryan 6 mentioned earlier, and that well flow tested at about 4,000 7 barrels a day, 36 API gravity oil. The Bermuda is the primary 8 development target. The prospective locations in the stratigraphically younger Cairn Interval carry more risk, and fewer potential reserves, and those will be tested on an opportunistic basis as we develop this reservoir. COMMISSIONER SEAMOUNT: Are you going to discuss your reasons for believing that there's lateral reservoir quality sands in the MR. MOOTHART: Yes, I will. COMMISSIONER SEAMOUNT: in the in 17 camera session? 18 MR. MOOTHART: Yes. 19 COMMISSIONER SEAMOUNT: Okay. 20 MR. MOOTHART: Actually, they'll be in the 21 public session. 22 COMMISSIONER SEAMOUNT: Okay. 23 MR. MOOTHART: So, the vertical limits of the 24 pool that we're proposing are the T4.1 interval at 4,958 subsea 25 tvd, and the T2 interval at 5,297. MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 14 .) ., . 1 This is a map similar to what Ryan showed earlier. 2 This is a map showing the aerial extent of the proposed pool 3 area. That's this bold line here. Ryan also pointed out its 4 relationship to the current southern boundary of the Kuparuk 5 River Unit through exploration penetrations. And what you see 6 on the map also is in the green contours, this is a current 7 interpretation of the net pay within the Bermuda Interval, and 8 then in the red contours is net pay for prospective Cairn 9 Interval that we're proposing, although this does not encompass 10 all of Cairn potential out here. The pool name, Meltwater, is 11 based upon the -- both the prospect and the exploration well 12 names. 13 Next, I'm going to show a seismic line that basically . 14 trends from the northwest to the southeast down across this 15 area. This northwest/southeast trending seismic line, 16 basically, it extends from the shelf margin up here, Cenomanian 17 aged shelf margin up here down into the shelf slope. The 18 yellow lines here are faulting that is evidenced up on the 19 shelf margin. The Bermuda Interval, again, our primary 20 development is -- this interval here, it's -- the top of it, 21 T3, is noted by this yellow to orange line, here, pick, and E2 22 by this green pick here. These sands are deposited as slope 23 apron deposits on the Cenomanian aged slope. This faulting 24 that we see at the shelf slope margin likely helped create some 25 of the accommodations space that allowed for these sands to . MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 15 · · · . \ ). ) . 1 accumulate. In the seismic line, you see this brighter red to 2 green, upper portion of the Bermuda Interval, and then this 3 black to dark blue coloring here, these are just some of the 4 amplitude signatures that we see associated with this interval. 5 6 Over to the east or southeast of Bermuda and 7 stratigraphically higher, we see some of the amplitude 8 signatures th~t we associate with Cairn Interval. These are 9 deposited in a stratigraphically higher section. They're also 10 offset to the east from the Bermuda Interval, distinctly, a 11 separate accumulation, and the trend of these deposits are more 12 into the page here on the map. They trend more north to south 13 rather than the northwest/southeast direction of the Bermuda 14 Interval, and they're generally more linear to sinusoidal in 15 map view, and I'll show that in the next map. This bright 16 reflector down here is the C35 interval, and this is a regional 17 sequence boundary that can be mapped out here. 18 Next, this is basically a map view of the maximum 19 seismic amplitude between the C35 interval that was down below 20· the Bermuda, and the T4.1 seismic picks which defines the top 21 of the Cairn Interval. What this map shows is the maximum 22 amplitude within that window. The seismic line, again, that we 23 just looked at ran from the northwest to the southeast. In 24 this location up in here is the shelf margin where we saw some 25 faulting taking place so this is amplitudes from the sands MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 16 · · · 6) CJ 1 deposited down on the slope. These sands are fed to the slope 2 by a system of gullies that are insized into the shelf margin 3 at the time of sea level low stand. The Bermuda Interval, 4 itself, is channelized to lobate in geometry. The trend of the S accumulations are generally from the west to the east 6 southeast. The Cairn Interval, I've got outlined here further 7 to the east. As you can see that these tend to be narrower, 8 more linear to sinuous in geometry, and that the trend of these 9 accumulations generally are more north to south. 10 COMMISSIONER SEAMOUNT: Do you have any feeling 11 for net pay in the Cairn relative to the Bermuda? 12 MR. MOOTHART: It's thinner. 13 COMMISSIONER SEAMOUNT: Okay. 14 MR. MOOTHART: The Cairn Interval tends to be IS more a nested series of channels that are backfilling a larger 16 channel complex, so they tend to be thinner than the Bermuda. 17 And these are more oriented parallel to the base slope. Both 18 accumulations are thought to be stratigraphic traps. Sand 19 distribution is what controls the hydrocarbon distribution, and 20 one thing about the slope apron deposits is that these tend to 21 be very discreet accumulations that are controlled by the local· 22 accommodation space available for these sands to come to rest 23 on the slope. 24 This is a map of the top of the Bermuda Interval, the 25 T3 interval structure map. What you see is generally the MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 17 .¡ C) . 1 structure out here dips about two to three degrees from the 2 west northwest down to the south or east southeast, excuse me. 3 The top of the Bermuda Interval generally runs from about 4 4,700 -- approximately 4,700 feet subsea tvd to 5,500 feet 5 subsea down here to the east. There is some faulting in the 6 updip portion. This was the faulting at about the shelf slope 7 margin that I showed in the cross section, and some of these 8 other features along the southern and northern boundary and 9 then also to the east here are younger shale-filled -- what 10 appear to be shale-filled channels that act as boundaries .to 11 our sand accumulation. This feature here is actually a younger 12 slump feature which appears to cut out part of the Bermuda 13 Interval. This map is the top of the Cairn or T4.1 interval . 14 structure map. The dips out - - the Cairn Interval are similar 15 to that of the Bermuda Interval, generally, west to east or 16 southeast. Faulting is the same. These -- this interval 17 generally is about 150 to 200 feet the structure above that of 18 the Bermuda. One thing to note, and I made mention of it in 19 the cross section, was that due to the offset of prospective 20 Cairn Intervals off here to the east, and, in fact, the 21 structural dip, the Cairn Interval -- respective Cairn 22 Intervals are generally structurally level to or below those 23 depths of the Bermuda. 24 Let's hold on to that slide just for a second. What 25 I'm going to do now is talk a little bit about the discreet . MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 18 &') c · 1 nature of these accumulations, these slope apron fan deposits, 2 and what I want to do is I want to use Tarn as an analogue. 3 Tarn, of course, is located as Ryan mentioned earlier about ten 4 miles north of Meltwater. It's another slope apron fan, another 5 deposit fed by slope gullies off the Cenomanian Age shelf. A 6 couple points to make again is that these tend to be discreet 7 accumulations controlled sediment controlled by local 8 accommodation space, and stratigraphic traps. No gas or water 9 legs were encountered in any of the exploration wells at 10 Meltwater within the Bermuda Interval. 11 Let's put that in the -- so, this is a net sand map of 12 Tarn. Again, this is nine miles north of Meltwater. At Tarn, 13 the Bermuda Interval is also the pay interval, and it is mapped · 14 into two separate lobes, basically, the northern lobe that I'll 15 refer to as here. This is off of drill site 2L pad, and the 16 southern lobe here drilled off of 2N 'pad. I'm using this as an 17 analogue to kind of point out the discreet nature of these 18 accumulations. 19 COMMISSIONER SEAMOUNT: Does Phillips have any 20 present day analogues? 21 MR. MOOTHART: By present..... 22 COMMISSIONER SEAMOUNT: It says stratigraphic 23 analogues, sedimentary analogues, for example, off the Coast of 24 California, anything like that, if they..... 25 MR. MOOTHART: Okay, you're -- modern. · MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 19 20 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · MET ROC 0 V R T R E P 0 R TIN G, INC. 25 the approximate location of that. That was at 5,141 subsea. 24 cap or gas oil contact that's noted by the red line on the map, 20 wells that they drilled 2L3 29A, and this location in the up 21 dip location at 2L Pad encountered a gas cap. We had sand in 22 the well, and tested a gas out of it. Based upon RFT data and 23 2L 329 and 2L 315, we were able to interpret a estimated gas Okay. At Tarn, in the drilling of Tarn, one of the 19 18 more as gullies. These are single point sources. 17 aren't anywhere near that scale. That's why we refer to them 16 be a kilometer to three kilometers maybe wide. These features 15 are discussed, they talk about canyons feeding them that will MR. MOOTHART: A lot of times when turbidites 14 · COMMISSIONER SEAMOUNT: Okay. 13 MR. MOOTHART: I don't have a feel for that. 12 11 extent of these compare? COMMISSIONER SEAMOUNT: How does the aerial 8 gullies, there's 9 onto the shelf. 10 actually gullies that come all the way back 7 California or Oregon. I'm thinking Point Reyes, some of those 6 analogue, you'd probably be looking at off the Coast of MR. MOOTHART: If I had to pick a modern day 5 COMMISSIONER SEAMOUNT: Modern day analogues. 4 MR. MOOTHART: Modern day analogues. 3 2 that to where you know what it looks like? COMMISSIONER SEAMOUNT: Or have you gone beyond 1 · C) &y . . . c} .) 1 And the point I want to make is that at 2N Pad in the southern 2 lobe, no gas has been encountered, and, in fact, we've got oil 3 present and production at 2N approximately 400 feet higher than 4 the gas-oil contact at 2L Pad. So, that's even as close as 5 these two sand bodies are, there is fluid isolation between 6 them. And I want to note, again, that no water life has been 7 found within the Bermuda at either Tarn or the exploration 8 wells at Meltwater. 9 Kind of building off the wells that I talked about on 10 the last map, this is a lot of RFT data from Tarn and 11 Meltwater. off· to the left here, this leftmost set of data, 12 that is from Tarn 2N or Tarn 3A, excuse me. This is from the 13 southern lobe at Tarn. This well here with the blue circles, 14 that's 2L 315. That's in the - - located in the northern lobe 15 down dip of the gas-oil contact. This is the RFP pressure from 16 2L 329. This was a well updip within the gas lag of the 17 northern lobe, and then I'll talk about the Meltwater wells 18 here. This is Meltwater North 2A, the pink color, and 19 Meltwater North Number 1 in green. What we see scale on the 20 bottom is the divisions are 50 psi difference. What we see in 21 the 2N to 2L is roughly about a same oil gradient plQtted but 22 roughly about ten to fifteen psi difference between the 23 pressures. This is gas gradient down from the RT pressure 24 updip at 2L Pad. The point where that intersects, the oil 25 gradient from the 2L 315 downdip in the oil lag, that's our MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 21 · · · ~} .) 1 interpreted gas-oil contact, and 1,541 at 2L in the northern 2 lobe. 3 What you notice from the Bermuda Interval RFT data at 4 Meltwater is they have essentially the same oil gradient as at 5 Tarn. There is about a thirty to fifty psi difference between 6 pressures between Tarn and Meltwater that's nine miles to the 7 south. Also, there's about a fifteen to twenty psi difference 8 between individual wells at Meltwater, and this is potentially, 9 we could have some communication problems between different 10 wells or different elements in different facies. This has b~en 11 noted and is taken into account in our development plan. 12 COMMISSIONER SEAMOUNT: What are the precision 13 of these RFT? Do you have any feel on that? Plus or minus 14 twenty-five, is that - - or are they a lot more precise than 15 that? 16 MR. MOOTHART: They're a lot more precise than 17 that. I don't have a good handle on that but, generally, I 18 think they're between, you know, maybe plus or minus five. 19 COMMISSIONER SEAMOUNT: So, you believe those 20 differences are real then? 21 MR. MOOTHART: I believe..... 22 COMMISSIONER SEAMOUNT: Okay. 23 MR. MOOTHART: .... .the differences are real. 24 Now, I want to talk a little bit about the sands themselves. 25 This is a quartz feldspar lithic ternary diagram, or FL MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 22 . .. . . } . 1 diagram, that plots the concentrations of quarts feldspar and 2 lithic fragments of the sand in its relation to each other. 3 One thing that we notice -- well, on this plot I've got both 4 Tarn data plotted. The Meltwater, which is in the red to 5 orange colors that you see here, and then a Meltwater South 6 well. One thing to notice right off the bat is how all these 7 rocks plot way down in the lithic corner. These are generally 8 quartz poor rocks. That quartz makes up about twenty percent 9 of the bulk volume. They're largely comprised of sedimentary 10 and metamorphic rock fragments as well as organic rock 11 fragments. The sedimentary rock fragments and metamorphic rock 12 fragments are typically composed of philites to sedimentary 13 extrabasinal fine grain silt stones, clay stones. The volcanic 14 rock fragments are generally composed of largely pyroclastic 15 glass shards. A lot of volcanics in this section. Most the 16 time these are a lot of these are altered to analcite, and 17 one of the things that we see common in the Bermuda Interval is 18 an analcite cement due to the alteration of this volcanic 19 glass. 20 Next slide is basically the same core data plotted 21 again but this time on a lithic ternary diagram to where we 22 have sedimentary rock fragments in the uppermost corner of the 23 triangle, volcanic rock fragments in the left lower, and 24 metamorphic rock fragments in the right lower. One thing that 25 I want to point out with this plot, again, Meltwater is in the MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 23 · · · . ..~ c) 1 red to yellow-orange colors, Tarn is in the blue, the dark blue 2 colors is that at Meltwater, these are generally, you know, 3 again, overplotting the Bermuda composition, sand compositions, 4 very similar sands suggesting the same provenance or sediment 5 source for these. As we would expect they're the same age, 6 same general setting. But one thing to notice is that the 7 Meltwater sands, if anything, may show slightly less volcanic 8 content than the Tarn Interval. There's a slight shift in the 9 data. 10 This plot is a porosity permeability cross plot. 11 Again, following the same color scheme as on the previous two 12 slides. The Meltwater wells are plotted in the red to kind of 13 yellow-orange color, and Tarn in the dark blue colors. 14 I want to talk a little bit about the porosity and 15 permeability and also some of the saturation, the rock quality 16 characteristics of Meltwater. For the sands in Meltwater, the 17 porosity averages rough- -- porosity ranges from seventeen to 18 twenty-five percent, averages approximately twenty percent. 19 That's in this area here. Permeability ranges from one 20 millidarcy to eighty millidarcies, and averages approximately 21 ten to fifteen millidarcies. This is somewhat facies-dependent· 22 within the accumulation. I'm not going to show a plot of water 23 saturation from the cores but basically, the raw uncorrected 24 saturation measurements from the core, when I say uncorrected, 25 I mean uncorrected for fluid invasion from fresh water drilling MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 24 .) .) . 1 fluids. They average fifty-one percent in these rocks. That's 2 too high. We've got evidence of fluid invasion into those 3 cores. One of the key things we're doing now with the first 4 development well that we're drilling is gathering a low 5 invasion core with tracers so that we can make an accurate 6 determination of our water saturations and some of our other 7 properties. But if we take our log model and start 8 calculating, trying to calculate some water saturations for the 9 wells here, what we. generally see is that in the high energy 10 channelized facies our average calculated water saturations 11 at -- are about forty-five percent. This also seems a little 12 high to us, and is thought to be the result of because this 13 high energy channelized facies carries a lot of mud stone rip . 14 ups, that there's a lot of scouring power within these facies 15 as they're being deposited and coming down the channel. So, 16 they entrain a lot of the finer grain material that was 17 deposited before them. If you get enough of these, then you 18 get a conductive pathway set that affects your resistivity 19 measurements, and as such, the resistivity affects the 20 saturation calculation. The..... 21 COMMISSIONER SEAMOUNT: Have you produced any 22 water at all. .... 23 MR. MOOTHART: No. 24 COMMISSIONER SEAMOUNT: . . . . .on any of these 25 tests? . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 25 . 6) c 1 MR. MOOTHART: No water was -- no water was 2 produced in the tests at all. And it's good to note that 3 Meltwater North Number 1 was testing the high energy, this high 4 energy facies that has all these mud stone rip ups, and that's 5 the well that tested 4,000 barrels a day. 6 So, in the lobe facies are more lobate facies at 7 Meltwater. Calculated water saturations average about thirty- 8 two percent. This is pretty much in line with what we're 9 seeing at Tarn, too. 10 The net pay cutoff set we use out here within our model 11 basically use a one millidarcy permeability cut off. This 12 equates to roughly a seventeen percent porosity cut off, and 13 also to a sixty percent water saturation cut off. Net pay . 14 model that we use at Meltwater at this point is very similar to 16 17 18 19 20 21 22 23 24 25 . 15 that that was used at Tarn as you would expect with the lithologies being similar, and the log response is basically a function of lithology, the main difference being that we correct Meltwater for its electrical -- measured electrical properties from the core plugs. I think at this point is when we'd like to go into confidential session. COMMISSIONER SEAMOUNT: Okay. Could you describe what the information consists of without divulging any confidential information? MR. MOOTHART: Just a summary? MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 26 27 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. questions. 25 COMMISSIONER HEUSSER: I don't have any 24 COMMISSIONER TAYLOR: Thank you. 23 MR. MOOTHART: Potentially. 22 21 proprietary information? 20 that information, would Phillips lose the value in that COMMISSIONER TAYLOR: Okay. And by disclosing 19 MR. MOOTHART: Yes, it is. 18 17 information to Phillips? 16 information that you're going to present, is this proprietary COMMISSIONER TAYLOR: Mr. Moothart, is this 15 COMMISSIONER SEAMOUNT: Okay. 14 MR. MOOTHART: Yes, it does. 13 12 or..... 11 you saying it identifies potential outside the proposed PA COMMISSIONER SEAMOUNT: Does it identify -- are 10 9 haven't been drilled on yet. 8 and prospects that exist within our exploration groups that MR. MOOTHART: Because it is upside potential 7 6 holding the information confidential? COMMISSIONER SEAMOUNT: What's the reasons for 5 4 show is upside potential in this area. MR. MOOTHART: Basically, what we're going to 3 2 information is it? COMMISSIONER SEAMOUNT: Yeah, what kind of 1 e) '. ) . . . 28 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. the Meltwater oil pool that we're proposing within the Kuparuk 24 I discussed Rule Number 1, the field, and pool name. This is MR. MOOTHART: To summarize my testimony here, COMMISSIONER SEAMOUNT: Okay. Thank you. 21 seismic mapping. 20 domain yet for roughly another year, and then also some of the 19 exploration wells at Meltwater, which aren't in the public MR. MOOTHART: Showed the well logs for the 17 information -- what kind of data did you show? COMMISSIONER SEAMOUNT: What kind of prospects. potential in the area, and showed some of the exploration MR. MOOTHART: Basically, I discussed upside confidential information? could you summarize what you talked about without divulging any COMMISSIONER SEAMOUNT: Okay. Mr. Moothart, (Public summoned to room) (Confidential session) (Public excused from room) COMMISSIONER SEAMOUNT: Okay. won't be very long as it is. employees, and Oil and Gas Conservation Commission staff. It MR. MOOTHART: Basically, the Phillips' 2 the room and identify who you would like to stay? COMMISSIONER SEAMOUNT: Okay. Could you peruse C) .) . 25 23 22 18 3 4 5 6 7 8 9 10 11 12 13 - 14 15 16 1 . 11 12 13 Okay. .' 14 15 16 17 hand. 18 19 20 . . .) a) 1 River Field. Rule 2, pool definition. Meltwater North Number 2 2A type log, the vertical pool is defined between a T4.1 3 interval on that -- in that well at 4,958 feet subsea tvd, and 4 the T2 interval or pick at the base at 5,297 feet subsea tvd. 5 The geolo- -- the geographic limits of the Meltwater Pool are 6 Sections 1 through 36 of Township 8 North Range 70s. And that 7 concludes my testimony for this part. If there's any 8 questions, I'll take them. 9 COMMISSIONER SEAMOUNT: I don't have anymore 10 questions at this time. Does..... COMMISSIONER HEUSSER: No. COMMISSIONER SEAMOUNT: . . . . . anybody else? We may be asking questions later then. Would you like to be considered an expert witness? MR. FRAZER: Yes, I would. COMMISSIONER SEAMOUNT: Okay. Raise your right (Oath administered) MR. FRAZER: Yes, I do. COMMISSIONER SEAMOUNT: Please state your name, 21 who you represent, and what your qualifications are to be 22 considered as an expert witness. 23 MR. FRAZER: My name is Lamont Frazer. I 24 represent Phillips Alaska. My qualifications include a degree 25 in chemical engineering from the University of Michigan in MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 29 30 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · MET ROC 0 U R T R E P 0 R TIN G, INC. 23 that is relatively close to the Meltwater field. That MI is 24 from CPF2 at Kuparuk. And this is a plot showing slim tube 25 simulation results indicating that that misc- -- that that MI Meltwater is that we have an MI or a miscible injectant source 22 One of the things that is advantageous for us ctt 21 proposed pool rules associated with those topics. 20 development plan, our plan surveillance program, and the 19 18 reservoir engineering. I plan to cover recovery mechanism, 15 you're being accepted as an expert witness. 16 MR. FRAZER: Thank you. What I would like to 17 talk about is primarily some of the topics associated with 10 COMMISSIONER SEAMOUNT: Thirteen. Do the other 11 Commissioners have any questions? 12 COMMISSIONER HEUSSER: No. 13 COMMISSIONER TAYLOR: I don't. · 14 COMMISSIONER SEAMOUNT: . Okay. Mr. Frazer, MR. FRAZER: Thirteen. 9 8 Alaska? COMMISSIONER SEAMOUNT: How many years in 7 6 reservoir engineering. 5 years I have worked in Alaska primarily in the discipline of 4 Texas, Louisiana, and the Gulf of Mexico. The last thirteen 3 years of petroleum engineering in the states of Oklahoma, 2 University of Alaska-Anchorage in 1995. I have almost twenty 1 1981, a masters in environmental quality engineering from the · e) e) e . . () () 1 is miscible at Meltwater conditions with the Meltwater crude. 2 And this is a plot showing recovery as a function of slim tube 3 operating pressure. And when there is a slope change between 4 these two lines, that is indicative of the MMP or the minimum 5 miscibility pressure. It suggests that we have a minimum 6 miscibility pressure at Meltwater of approximately 2,250, and 7 we measured,the reservoir pressure in the Meltwater North 8 Number 1 exploratory test at 2,400 psi. So, what that 9 indicates is that the MI that we're going to be -- that we 10 would like to use at Meltwater is actually overrich. We could 11 lean it up with produced gas and still have it be miscible at 12 Meltwater reservoir conditions. 13 Because we have a miscible source available to us, we 14 wanted to look at the advantage of going with the miscible 15 recovery process, so we constructed a series of pattern models 16 to evaluate that. We used Tarn as an an~logue to help us 17 develop some of the reservoir properties. This is a plot 18 showing porosity as a function of permeability for the higher 19 energy facies or the combined flow Turbidite facies at Tarn. 20 This is a similar plot, again, showing reservoir 21 properties for our Tarn analogue, and it shows water ,gaturation 22 as a function of porosity. 23 Those previous plots were used to help construct the 24 reservoir model that your -- the depiction of the reservoir 25 model that you see in front of you, and this is a model showing MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 31 C) C) . 1 permeability for a slice of the reservoir. The warmer colors 2 represent higher perm rock, and the cooler colors represent 3 lower perm rock. This model was based on a Stochastic 4 description so every cell has variable properties that we find 5 within various Turbidite facies. Simulation results from that 6 idealized model when using a five -- idealized five spot 7 pattern, provide the following recovery plots. And this is a 8 plot showing recovery as a function of total HCPVI or total 9 hydrocarbon pore volume injected. The squares represent the 10 recoveries that we would expect to get with an lean gas type of 11 a flood, a non-miscible process. The green circles represent 12 the type of flood response we would see with a MI floor or a 13 miscible gas flood. Triangles represent a water flood . 14 response. But what's really interesting is the -- I should say 15 diamonds represent a water flood response. What is really 16 interesting though is the type of response we get with an MWAG 17 recovery process, which is represented by the triangles. In an 18 idealized five spot pattern model, it shows that we have an 19 incremental recovery benefit of approximately thirteen percent 20 OOIP over water flood. And this is using a twenty percent 21 22 23 24 25 . HCPVI cumulative slug size for both the MWAG process, which is a miscible alternating water -- miscible gas alternating water cycle project, and we also use the twenty percent HCPVI cumulative slug size for the MI flood. Unfortunately, we don't often get the idealized MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 32 · · · .-) ~) 1 response that we get from our simulation models, so I would 2 like to briefly step through the process that we went to to 3 scale up those to field level results. What we did is we ran 4 our Stochastic pattern models fully compositional so we're 5 looking for incremental recovery on a miscible basis, and we're 6 running those for different lithofacies, the higher Turbidite 7 energy facies and the lower energy facies as well. We then 8 combine those models into a -- dimensionless curves, and we 9 volumetrically weighted each model to represent that portion of 10 the reservoir that we think is relative to that facies. For 11 example, we had about forty percent of our Meltwater facies 12 fall into the higher energy Tarn analog, and about sixty 13 percent falling into the low energy Tarn analog. We combined 14 those into a dimensionless curve set of curves I should say. 15 We then ran a set of homogeneous models. We ran them with 16 black oil so we didn't worry about tertiary recovery response, 17 and we looked at various pattern configurations that we thought 18 would be representative of what we would actually encounter in 19 the field. Because we cannot accurately predict where the sand 20 lies, we expect to have some irregular patterns, and we expect 21 our well spacing to be non-ideal. Some wells will b~ 'closer 22 than others to each other. We then ran those models on a 23 homogeneous, and compared those to an idealized five spot 24 pattern on a homogeneous basis, and developed a relationship 25 describing the aerial inefficiencies associated with what we MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 33 e 1 2 3 4 5 6 7 8 9 10 ~) I.) think will be real world type patterns. We then applied those radial -- those aerial inefficiencies to our dimensionless Stochastic model to come up with what we expect in the field. That is, that the MWAG which previously showed a thirteen percent incremental recovery over water flood, we actually expect to get results approximately nine percent incremental recovery over water flood. And that ties into the initial MWAG justification. The reasons that we're going MWAG initially, they include the MWAG recovery benefits which are estimated at approximately nine 11 percent incremental over water flood. They also include the 12 impact that we're hav- -- that we would have the Kuparuk. 13 Because Meltwater is a new reservoir that has not previously e 14 seen gas injection, it would be -- it's a very efficient place 15 to inject MI and store gas relative to Kuparuk. Since Kuparuk e 16 is gas handling limited, any reduction in recycled gas coming 17 from gas that's injected into the ground and recycling through 18 the reservoir would have a beneficial effect in terms of rate. 19 So, Meltwater is expected to have a beneficial impact at 20 Kuparuk in terms of storing gas. In addition, looking at the 21 targeted drill sites at Kuparuk, where we want to inject MI in 22 the future, we will we see no change in getting to tnose 23 drill sites whether or not we go to Meltwater. So, there is no 24 appreciable adverse recovery impact estimated at Kuparuk. 25 Another reason for initial MWAG justification is the MI MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 34 . ., ,) . ) . 1 availability. We have the infrastructure in place as well as a 2 MI that is miscible with the Meltwater crude at Meltwater 3 conditions. But the -- one of the key reasons though that we 4 want to go initial is because of the infrastructure opportunity 5 window. What I mean by that is this. Even though we have the 6 infrastructure in place, the MI distribution system that we 7 will be using at Meltwater carries MI to the Western Kuparuk 8 drill sites. Those drill sites are relatively mature on an 9 MWAG basis, and, hence, we will likely be -- unlikely be 10 injecting MI five to ten years down the road. If we were to 11 wait and not inject MI initially at Meltwater, that 12 infrastructure may not be available. And the reason is there's 13 several uses for the piping that carries the MI. It's a IIÞ 14 potential high pressure gas lift opportunity for the Western 15 Kuparuk drill sites. It could help us debottle neck our water 16 injection, or debottle neck our production. So, taking 17 advantage of Meltwater initially with a MI distribution that's 18 al- -- system that's already in place, we will not adversely 19 affect Kuparuk. 20 21 22 23 24 25 .' COMMISSIONER HEUSSER: Now, did I hear you say that these Western Kuparuk drill sites, that the MI p~dcess there is not time and pressure sensitive? MR. FRAZER: I'm sorry? COMMISSIONER HEUSSER: So, delaying MI injection at those Western Kuparuk drill sites is not going to MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, SuÏJe 425 Anchorage, Alaska 99501 (907) 276-3876 35 36 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · MET ROC 0 U R T R E P 0 R TIN G, INC. recovery at Kuparuk by doing MWAG at Meltwater. 25 and to our best ability, we don't see any appreciable change in 24 23 handle the gas. So, when taken together, those two counteract, 22 reserve because they have to shut in wells because we can't 21 Kuparuk would realize. But they would also realize some lost 20 cycled gas, there would be some incremental recovery that 19 gas because we would be cycling it so much. But with that 16 handling limits, that would offset that reserve loss. Does 17 that make sense? If we did not do Meltwater, we would have to 18 shut in more wells at Kuparuk because we couldn't handle the 15 that, but because we would have to shut in wells due to gas 14 so there would be some reserve loss associated at Kuparuk from · 13 benefit by continuing to cycle MI at a very mature drill site 12 that would result from that. There would be a slight recovery 11 sizes if we didn't ,do Meltwater, so there would be two effects 10 we would probably have to inject larger c~mulative MI slug 9 not we pursue MWAG at Meltwater. The difference being is that 8 at Kuparuk, we would be able to reach regardless of whether or 7 was the same drill sites that we're targeting for MWAG process 6 process five to ten years in the future. What I said earlier 5 Therefore, they will likely not be undergoing an MWAG recovery 4 mature, and their life on a MI -- on a MWAG process is limited. 3 components. The Western Kuparuk drill sites are relatively MR. FRAZER: That -- what -- there is two 2 1 affect recovery? · .) c) 37 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. 23 sea sands that are not in the western side. They're more in 24 the 2X, 2Z side of CPF2, which is the eastern side. The 25 western side is also mature, but it's not as mature as the sea time, the most mature areas that we're dealing with are mature 22 us with some of the mature areas, but the -- at this ,point in 21 MR. FRAZER: We would use that capacity to help 20 19 you're describing as the western mature flood drill sites? 18 that additional gas handling at CPF2 to handle the -- what COMMISSIONER HEUSSER: So, you wouldn't use 17 MR. FRAZER: No. 16 15 Meltwater? 14 would you revisit your decision to reroute thatMI to . COMMISSIONER HEUSSER: And if that happens, 13 12 to help de-bottleneck the gas train, so the answer is yes. MR. FRAZER: We do have plans in place at CPF2 11 10 increase gas handling at Kuparuk? COMMISSIONER HEUSSER: Are there any plans to 9 8 the injection machines that inject the gas back into reservoir. 7 CPFl has a bottleneck primarily in the third stage, which is 6 machines which is our first and second state of compression. 5 injection machines. CPF2 has a bottleneck in the gas-lit 4 CPF2 is primarily -- we have our gas-lit machines and then our MR. FRAZER: The field is gas handling limited. 3 2 it, CPF2 that's gas handling limited? COMMISSIONER HEUSSER: Is it just -- what is 1 e ~..\ 'I } ~) · .) -¡ ..,\ 1 sands I just described, the 2X and 2Z. We are in the process 2 of abandoning drill sites sea sand MWAG floods at some of the 3 eastern drill sites as we speak. We're giving up on MI 4 injection. We've already given it up at 2Z, for example. We 5 predict that we'll be giving up on MI injection on the Western 6 drill sites within the next few years. 7 COMMISSIONER HEUSSER: Okay. Thank you. 8 MR. FRAZER: Okay. In terms of development 9 drilling, as Ryan mentioned earlier, or Steve mentioned 10 earlier, we are currently drilling our first development well 11 at Meltwater right now. We spudded the end of last month, and 12 we plan to drill approximately seventeen wells this year. We 13 plan to drill the wells on a phase basis with regard to · 14 regions. We would like to go ahead and better understand what 15 16 17 18 19 20 21 22 23 24 25 · various regions can provide in terms of long-term staple production before we go ahead and fully develop the offset wells. We also plan to test Cairn early in the program, and our strategy is to develop the best portions of Meltwater early· for the rate benefits or the sweep spots, at the same time testing some of the peripheral regions to better understand the' long-term performance of those regions. With regard to 2002, we plan to complete our drilling program which is another nine wells to give us a total of twenty-six, and we will likely have a drilling break during the MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 38 ·) .. , ) e 1 exploration season, which would be the end of December this 2 year through the first quarter of next year. 3 In terms of our injection management strategy, our 4 plans are to maintain reservoir pressure at a sufficient basis 5 to ensure that we do not jeopardize tertiary recovery benefits. 6 We also plan to minimize a number of injectors that we have to 7 give us an opportunity to better underst~nd which wells are 8 talking with what. The reason that's an advantage is with 9 complex geology, we simply cannot go out there and implement a 10 pattern flood because as Steve showed earlier there may be 11 various facies with wells right next to each other that simply 12 do not talk or communicate with one another. So, this will 13 give us a better opportunity to understand what is talking with e 14 each other before we finalize our patterns. 15 We plan to have an aggressive initial MI injection 16 schedule, and the reason for this is as I mentioned earlier, it 17 will help the GKA from a rate standpoint by allowing us to put 18 gas in a place that has a very high gas storage efficiency. We 19 also plan to optimize our cumulative MI slug size on a pattern 20 basis. Obviously, there will be some patterns that will have a 21 faster MI breakthrough than we desire. If we cannot ,Correct 22 that through pattern conversations -- I'm sorry, through 23 producer conversions to injectors, then we will likely have to 24 live with an overall slug size that's smaller than most 25 patterns. Likewise, if we have patterns and we found that . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 39 e) .) e 1 there is very little MI breakthrough, that we have a very 2 efficient sweep process, we'll be able to increase the slug 3 size in those patterns. 4 Finally, late in the life of the field, we plan to have 5 a lean gas sweep, and the reason for that is it will allow us 6 to recover some of the NGLs that are in the MI that are trapped 7 in the reservoir during the MWAG process. 8 9 you. 10 11 12 injection COMMISSIONER HEUSSER: I've got a question for MR. FRAZER: Sure. COMMISSIONER HEUSSER: You -- under your management strategy, maintain reservoir pressure to 13 ensure tertiary recovery be'nefits, and then you're going to . 14 minimize injectors, how else are you going to maintain your is reservoir pressure? 16 MR. FRAZER: We can -- at a produ- -- our 17 calculations plus field data at Tarn suggest that we can 18 maintain reservoir pressure at a two to one producer to 19 injector ratio. From a sweep standpoint though, we would like 20 to have a one to one producer to injector ratio. So, our 21 initial plan would go in -- we would go in with a two, to one 22 producer to injector ratio, maximize rate, understand what is 23 talking with what, and still maintain reservoir pressure, and 24 then convert within the next few years to better improve sweep. 25 Slide 33 represents a production profile. It's a plot . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 40 I e) e) · 1 showing oil production as a function of time. The green 2 circles represent Meltwater production, and the red dìamonds 3 represent the impact to the GKA as a whole. Now, what this 4 illustrates is that there will be some back out that occurs at 5 Kuparuk and Tarn and some of the other satellites. And the 6 reason is even though Meltwater is a very efficient place to 7 store gas, there will still be gas production associated with 8 the oil production, and that gas production will cause some of 9 the highest fuel oil wells elsewhere at the GKA to be shut in 10 because of our surface facility handling limits on gas 11 compression. 12 Given the number of uncertainties we have, there is 13 quite a bit of optimization that we still need to do. Some of · 14 it will be simulation based, and some of it will be performance 15 based. With regard to that, we plan to optimize the cumulative 16 slug size. As 'I talked about, that will be done on a pattern 17 basis. The MI enrichment is another level that or another 18 issue that we talked about briefly. Because we have an overly 19 rich MI, there is a possibility that in the future, we may want 20 to lean that up and customize it for Meltwater by mixing it 21 with produced gas. 22 Well spacing, we are currently planning on having 23 nominally a hundred acre well spacing. Again, given the 24 inability we have to predict which wells are talking with what, 25 we may have to go ahead and have infilled -- an in fill program · MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 41 .) . ) · 1 to help us recover areas that are having some communication 2 problems. 3 Horizontal and high angle wells, we plan to use those 4 to help us address some of the communication problems that we 5 talked about. For example, two facies that do not communicate 6 with one another,' we can penetrate them both with a single well 7 and ensure that there is communication across that through that 8 one well bore. In addition, horizontal wells could offer some 9 rate benefits on our producers. 10 Pattern configuration, as I mentioned, we will rely on 11 field data to tell us which are the best wells to convert in 12 the future to optimize our sweep. 13 And well location refinement, as we begin to delineate · 14 Meltwater and better understand what our seismic attributes are 15 telling us, we'll have to refine our current plans for where we 16 would like to place our wells. 17 In terms of well issues, we expect over half the wells 18 to flow naturally. They'll flow against about 350 pounds back 19 pressure. We are equipping the well bores though for gas lift. 20 Since we don't have any lean gas available at Meltwater for 21 lift, we would use MI initially for lift, and then on~e the 22 MWAG process is over with, the MI distribution system would 23 likely carry lean gas to Meltwater and offer a lift gas source 24 at that time. 25 Another means that we plan to use for artificial lift · MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 42 e} .) . 1 is jet pumps. And what's interesting about jet pumps is not 2 only will they provide a means for us to lift some of our 3 weaker wells, but because we will use injection water coming 4 from CPF2, which is nominally 120 degrees Fahrenheit, that will 5 also mitigate paraffin deposition. And at Meltwater we have a 6 crude that's three and a half percent wax by weight, with a 7 cloud point of a 100 degrees F. So, by using jet pump lifts 8 with injection water as the power fluid, we will be able to 9 mitigate paraffin deposition in our tubulars. Ano- 10 COMMISSIONER HEUSSER: When you said natural 11 flow, what percentage of your wells would be able to flow 12 without artificial lift? 13 MR. FRAZER: We expect over fifty percent. .' 14 COMMISSIONER HEUSSER: Over fifty percent. 15 MR. FRAZER: Another possible artificial lift 16 scheme that we have is a possible back pressure reduction. If 17 Meltwater flows at higher rates than we expect, or if some of 18 the prospective that Steve showed you comes to fruition' and we 19 do have additional production in the area, there may be a 20 possibility that we'll install a booster station that will help 21 us overcome some of the backpressure problems. 22 Another well issue is our secondary targets, 23 principally, thin marginal Cairn. Now, what Steve had shown is 24 the heart of the Cairn, this southern Cairn play, and it was 25 relatively thick. Our concern is from a well bore standpoint . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 43 .' . ) ) · 1 is what happens if it's very thin, say, nominally ten feet. Is 2 it economic or if it isn't. And for us to understand that, we 3 will need to collect some production data and evaluate this 4 over a longterm basis. One of the things that we're asking the 5 6 7 8 9 10 11 12 13 · 14 · Commission to help us with though is to allow us to evaluate this and still honor annular isolation concerns, and that's shown on the next slide. Since the Cairn is about 200 feet tvd above the Bermuda Interval, if we were to go ahead and have annular isolation within a hundred feet of the Bermuda Interval, it really provides us no way of accessing the Cairn at a later date. If, however, on some of our early wells we're still on the data gathering standpoint we don't initially perf the Cairn and stimulate the Cairn, until we determine its economic viability, 15 we will be setting the crossover point and have no annular 16 isolation unle- -- for 200 feet tvd above the Bermuda. So, 17 what this scheme possibly could lead to is let's say we had a 18 ten foot zone of Cairn that we deemed uneconomic and we never 19 perforated or stimulated it and it was in this well bore, and 20 we wanted to use this well in the future as an injector, as I 21 mentioned earlier, we're going to have about half our injector 22 conversions occurring as we learn more. If that were the case, 23 it would leave us with a situation where we have an injector 24 with annular isolation that's approximately 200 feet tvd above 25 our perforated interval. And that is one area that we're MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 44 · · · .\ l -¡ 1 asking the Commission for help in helping us preserve the 2 option to go after some of this marginal Cairn and still honor 3 annular isolation regulations. 4 In terms of surveillance, we'll rely on well tests, gas 5 samples, and with gas samples, we will test and look at 6 compositional analyses to tell us if we're having MI 7 breakthrough or not, and we'll likely also use chemical tracers 8 to help us understand which wells are talking with what 9 producers. We'll also be using pressure measurements to help 10 us understand what portions of the reservoir are seeing 11 pressure support, and finally, we'll have surveillance logs to 12 help us. 13 Now, with regard to surveillance logs, we will run 14 those in our injectors. We don't have plans to run them in our 15 producers though because we will be fracture stimulating our 16 producers, and it really will not give us any beneficial 17 information. 18 In terms of the..... 19 COMMISSIONER HEUSSER: Excuse me. 20 MR. FRAZER: Yes. 21 COMMISSIONER HEUSSER: Your pressure 22 measurements, what's the frequency and the number that you 23 anticipate doing per year? 24 MR. FRAZER: In terms of the regulations that 25 we're proposing, I have that outlined in two slides. They're MET ROC 0 U R T R E P 0 R TIN G ,. INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 45 e) eJ . 1 just a couple of overheads from now. 2 COMMISSIONER HEUSSER: Okay. That's good 3 enough then. 4 MR. FRAZER: But, verbally, we would do it 5 whenever we saw the need to do it. We want to make sure 6 that -- we're investing a tremendous amount of money injecting 7 MI into the formation, and we want to make sure that that MI is 8 being put to use, and as a result, we will make sure that we 9 maintain the pressure. We're getting pressure support as 10 needed, and we're getting the sweep as needed. So, there is no 11 minimum frequency that we will -- that we have as a mindset 12 right now. We'll do what we need to do. 13 COMMISSIONER HEUSSER: Okay. .' 14 MR. FRAZER: In terms of pool rules that relate 15 to some of the topics that I've been talking about, they 16 include spacing units or injection well completion, reservoir 17 pressure monitoring, GOR exemption, timing of injection 18 startup, and reservoir surveillance reporting. And I'll go 19 through each of those. 20 The first is spacing units. We're proposing a minimum 21 of ten acre spacing. That will give us the flexibility to go 22 after areas where we do see non-communication issues. We're 23 also proposing that the wells be drilled no closer than 300 24 feet from an ownership change. 25 With regard to proposed rule 5, we're proposing that we . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 46 · · · &) c \. V / 1 do have less than 200 feet of annular is- -- less than 200 feet 2 to annular isolation from our top perforation except in cases 3 we're pursuing secondary targets as we outlined before. 4 With regards to pressure monitoring, the proposal we 5 have at minimum, an initial pressure survey on each well, and a 6 minimum number of pressure surveys that on an annual basis that 7 equates to the number of governmental sections. Now, this is 8 different than most of the pressure requirements that we have 9 pool rules for including Tarn and Kuparuk. On those pools, 10 what's typically done is there is a annual pressure required 11 for each governmental section. On small accumulations of this 12 nature though, it would make more sense to go ahead and target 13 pressures in areas where they're of most value as opposed to 14 each governmental section~ For example, we could have a single 15 well from a governmental section and be getting an annual 16 pressure on that one well every year, and it will add no value 17 because there's no issues associated with that, whereas if we 18 could use this to collect data elsewhere in the field, that 19 is -- that would be of more value, that would be of great help. 20 We're also proposing to have a pressure datum of 5,400 21 feet subsea, and we're proposing that the pressure surveys 22 consist of either stabilized static pressure measurements, 23 follow ups, build ups, multi rate tests, fill stem tests, or 24 open hole tests. We're proposing to report the results 25 quarterly, and we're also proposing that we'll report special MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 47 48 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. MR. FRAZER: Yes. 25 24 authorization to drill within 300 feet of the boundary. COMMISSIONER TAYLOR: Where you're asking for 23 MR. FRAZER: Yes. 22 21 ,proposed rule 3. COMMISSIONER TAYLOR: I have a question on 20 19 there any questions? And that concludes my testimony for this portion. Are 18 17 plans. 16 evaluation, and we also will include our future development 15 We're proposing that we have well allocation and well test 14 injection logs. Again, Cairn and Bermuda, distinct intervals. 13 reservoir pressure analysis, multi-interval production and 12 has a Cairn and Bermuda Interval that are distinct within it, 11 referring to interval, I'm referring to if we have a zone that 10 update, produced in injection fluids by interval, and when I'm 9 report, we propose that it include' a reservoir management 8 six months of production, and for our annual surveillance 7 We're proposing that we have injection start up within 6 make a lot of sense. 5 injecting gas into the reservoir, GOR producing limits do not 4 have a GOR exemption because on a MWAG process where you're 3 Proposed rule 9, GOR exemption, we're proposing that we 2 well. 1 tests or interference or pulse tests on a quarterly basis as ) ) . . . .' . 49 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. MR. FRAZER: No. 25 24 wells within the 300 feet? 23 plans? Are those wells that you've described, are any of those COMMISSIONER TAYLOR: And do you currently have MR. FRAZER: Yes, exactly. 17 300 feet or 18 right? 19 20 21 22 MR. FRAZER: Uh-hum (affirmative). COMMISSIONER TAYLOR: All the way around? more away from that boundary change on the inside, 16 if we could proceed without special approval so long as we were MR. STRAMP: I think what we're requesting is MR. FRAZER: Yes. 12 13 .- 14 now? 15 COMMISSIONER TAYLOR: Do you have plans right 9 close to -- that border right there would be one, for instance. 10 COMMISSIONER TAYLOR: Is your request then 300 11 feet within that exterior boundary? MR. STRAMP: Yeah. There can be if you get up .... . there is not an ownership MR. FRAZER: 3 boundaries? 4 5 6 7 change. 8 COMMISSIONER TAYLOR: Thank you. MR. FRAZER: Within the pool rule..... 2 change? Is there an ownership change between these pool rule COMMISSIONER TAYLOR: What's the ownership 1 e e) c) 50 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · MET ROC 0 U R T R E P 0 R TIN G, INC. 25 Brockway. I'm a drilling engineer for Phillips Alaska. My MR. BROCKWAY: Okay. My name is Thomas A. 24 23 qualifications are. COMMISSIONER SEAMOUNT: And what your 22 MR. BROCKWAY: Yes, sir. 21 20 witness? 19 who you represent, and do you want to be considered an expert COMMISSIONER SEAMOUNT: Please state your name, 18 MR. BROCKWAY: I do. 17 (Oath administered) · 14 15 hand. 16 COMMISSIONER SEAMOUNT: Please raise your right MR. BROCKWAY: Yes, I am. 13 12 you giving sworn testimony? COMMISSIONER SEAMOUNT: Okay. Let's see, are (On record) 5 6 7 8 record. 9 here? 10 11 MR. STRAMP: Mr. Brockway will be next. It's 11:08, and let's see, where are we going from COMMISSIONER SEAMOUNT: We're back on the (Off record) 4 Be back at 11:00. We're off the record. 3 further questions. I think -- let's take fifteen minute break. COMMISSIONER SEAMOUNT: I don't have any 2 COMMISSIONER TAYLOR: Okay. 1 · () C) 51 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. Brockway's. . . . . 25 COMMISSIONER SEAMOUNT: . . . . .Mr. 24 COMMISSIONER HEUSSER: No. 23 22 there any questions on. .... 21 thirteen years. Family still lives there. Sorry. Qkay. Are COMMISSIONER SEAMOUNT: I lived there for 20 COMMISSIONER SEAMOUNT: Really? What town? MR. BROCKWAY: Casper. True oilfield town. 19 18 MR. BROCKWAY: I was born there. 17 COMMISSIONER SEAMOUNT: Are you from Wyoming? 16 MR. BROCKWAY: Yes, sir. 15 COMMISSIONER SEAMOUNT: University of Wyoming? 14 13 12 Tabasco, Kuparuk infill work, gas storage work, to name a few. 11 Meltwater. I've worked on eastern boundary area expansion, 10 and now Phillips, planning and executing developments such as 9 I've been working as a drilling engineer with Arco, first Arco, 8 drilling and completion designs. And for the past five years, 7 Staff Engineer for Baker Hughes Intech designing and executing 6 and international. I spent four years as the Alaska Region 5 on the North Slope, Cook Inlet, throughout the United States 4 directional drilling, and running MWD tools. Vàrious locations 3 From there I spent about eight years working on the rigs, 2 the University of Wyoming in petroleum engineering in 1984. 1 qualifications, I obtained a bachelor of science degree from .) .) . . . · · · e) e) 1 COMMISSIONER TAYLOR: No. 2 COMMISSIONER SEAMOUNT: Okay. You are being 3 Mr. Brockway, you are being accepted as a expert witness. 4 Please proceed. 5 MR. BROCKWAY: We were -- as far as our well 6 construction and development plans for Meltwater, we're really 7 not reinventing the wheel here. What we tried to do is base 8 our development on past successful developments out at Tarn, 9 and in the Kuparuk in field work that we've done over the past 10 several years. What we've got is just really one standard 11 design in two different sizes. The well on the left here I 12 guess you consider our -- to be our conventional monobore 13 design, and what that consists of is a twelve and a quarter 14 surface hole in which you set nine and five-eighths inch 15 surface casing, and you drill out with an eight and a half inch 16 production hole through the reservoir zone, and run a seven 17 inch by four and a half inch tapered production casing string. 18 The slim hole version on the left is a similar design. The 19 surface hole on this is a nine and seven-eighths inch surface 20 hole in which you set seven and five-eighths surface casing 21 k,then drill out with a six and three-quarter inch prdduction 22 hole and run a five and a half by three and a half inch tapered 23 production string. 24 Couple of the key features on this -- on these we 25 call them monobore completions, the production strings in both MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 52 · · · ..) .) 1 cases are solid cemented liners which we will go in and 2 selectively perforate based on our well logs. The casing seal 3 receptacle right here basically takes the place of a production 4 packer. We can use that -- we'll set that above the production 5 zone as Lamont discussed earlier possibly above our shallower 6 test intervals. That will give us a test of our annulus down 7 to that point under the seal bore point here. And what the 8 monobore design allows us to do is to have a full bore access 9 from surface to tv allowing us really ease of perforating, 10 running post rig logs, and doing remedial work in the well 11 bore. 12 COMMISSIONER HEUSSER: Excuse me. I see that 13 you've got nipples for possible K valves. Do you intend to 14 install some sort of subsurface safety valve for all of those 15 wells capable of natural flow to surface? Or in your injection 16 wells? 17 MR. BROCKWAY: Well, we put this - - as a 18 general design, where we put this in put these nipples in up 19 there for that purpose. I guess. . . . . 20 MR. STRAMP: I might respond to that. We 21 we'll follow the -- our intention is to follow the same 22 guidelines as the rest of Kuparuk Field, and a couple years ago 23 those -- conventions changed where the only wells that meet 24 certain criteria of very high rates or very high gas potential 25 that we install subsurface safety valves in, so we do not MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 53 . . . .) .) 1 intend to install carte blanche subsurface safety valves in 2 these wells. Having the nipple at that location provides the 3 opportunity to do that in the future if we should need to or if 4 deemed by the Commission or others that it's needed I guess. 5 COMMISSIONER SEAMOUNT: What's your definition 6 of a very high rate? 7 MR. STRAMP: I don't remember the numbers off 8 the top of my head. There's a field standard operating 9 procedure that I'm pretty sure has been shared with the 10 Commission that specifies that information. We can get that to 11 you separately. 12 COMMISSIONER HEUSSER: Yes, please. 13 COMMISSIONER SEAMOUNT: Okay. 14 MR. FRAZER: It's a function of rate. .It's 15 also a function of locale. Wells near the airstrip are 16 required by these regulations to have some sort of safety 17 valves. So, it's a requirement of -- it has two components to 18 it. 19 COMMISSIONER SEAMOUNT: Okay. 20 MR. BROCKWAY: The other nipples here are -- 21 and the sliding sleeve are in there to accommodate ou~' jet 22 pump, possible jet pump type completions. We'll also have 23 probably one to five gas lift mandrels for a possible gas lift 24 depending on whether the wells are a producer or an injector, 25 and, of course, the departure and depth of the well. METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 54 .) .) · 1 Let's talk a little bit about casing and cementing 2 practices here. We'll -- I guess the bottom line on casing and 3 cementing is that we will operate all of our wells for drilling 4 and completion operations within the existing AOGCC 5 requirements with -- and Kuparuk -- approved Kuparuk Field 6 rules. Conductor will set at seventy~five feet, at least 7 seventy-five feet below ground level. That will allow us a 8 structure to attach our surface diverters to. We'll set our 9 surface casing at least to 500 feet below the permafrost, and 10 we hope to allow -- give ourselves some allowance for annular 11 disposal. operations in the future. 12 COMMISSIONER HEUSSER: Tom, how does that 13 surface casing depth of at least 500 feet below the permafrost · 14 compare to the Alpine Field? 15 MR. BROCKWAY: I believe Alpine is deeper. 16 It's a different structure, of course, out there. We're 17 farther up dip. I can't give you the exact numbers but I know 18 in this area, for example, the West Sak is quite a bit shallower, if you base it on a West Sak type of formation. It's quite a bit shallower here at Meltwater than it is even in 19 20 21 the main Kuparuk Field. 22 COMMISSIONER HEUSSER: So, it's kind of an 23 arbitrary 500 feet below the permafrost? You're not heading 24 for some sort of..... 25 MR. BROCKWAY: It's a minimum 500 feet. · MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 55 . 1 2 3 4 5 6 7 8 9 10 11 12 . . c) .) COMMISSIONER HEUSSER: .... ..shale or..... MR. BROCKWAY: We're looking for a competent shale or silt stone type tormation to set in. Based on what we've seen in the past on the exploration wells, that will give us what we believe that -- anywhere from that point on down will give us a competent shale to set in. On our first well, actually we set quite a bit, deeper and obtained a very high leak off test. MR. STRAMP: Yeah. Typically, we -- we're down around the 2,500 foot..... MR. BROCKWAY: Yes. MR. STRAMP: . . . . .tvd, which is well below the 13 base permafrost, looking for a good competent place, et cetera. 14 MR. BROCKWAY: That 500 feet isa minimum 15 number. You know, operationally, we would normally want to set 16 deeper. That's a minimum number for a competent shoe depth. 17 We're going to be using a standard Kuparuk type tree, 18 and wellhead assemblies are FMC Gen 5 wellheads. We've gone to 19 these pretty much standard throughout the Kuparuk Field on all 20 of our new wells. They offer a metal to metal seal, which is a 21 little bit better seal protection for overall operatiQhal life. 22 They've all got on the trees these fail safe surface safety 23 valves installed really in the upper master valve position on 24 the tree. Those are high-low pressure valves. All of our 25 wells out of Meltwater will have these whether they're MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 56 . -., . .) .) 1 producers or injectors. 2 The design, there's really no design difference the 3 large bore size for the Gen 5 wellhead and the slim hole. It's 4 just a change in the internal casing hanger that we used to 5 hang casing off. So, from the surface if you were to go out to 6 the pad, you wouldn't be able to tell whether it was a big bore 7 or a slim bore well by looking at the wellheader tree system. 8 As I mentioned, all of our trees will have these fail 9 safe surface safety well -- surface safety valves, and we'll be 10 testing those every six months. That is per our policy and per 11 regulation. 12 A couple of other regulations that I would like to 13 address. We have not seen either on any of the exploration 14 wells or on our current development well that we're drilling 15 any evidence of hydrogen sulfide, but as per regulations, we 16 will have HzS monitors throughout the rig. It's a standard 17 operating practice for us, PA, operating practice. We'll also 18 due to the remote distance this pad from the main Kuparuk Field 19 will have all of our HzS mud scavengers on location to allow us 20 quick response in the event that any HzS is seen. 21 As far as data gathering requirements, all of our data' 22 gathering plans center around the use of LWD tools in the hole. 23 We'll be running those primarily below the surface shoe, and 24 we'll be requesting some exemptions from this particular data 25 gathering requirement set under the regulations. Our first MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 57 e) .) . 1 well, we are obtaining a full set of logs, mud logs, from 2 surface, gamma ray resistivity down to the surface shoe and 3 then gamma ray resistivity neutron density logs below that to 4 tvd as well as a pretty full set of wireline evaluation logs. 5 The first -- the next few wells we will -- the second 6 well will be obtaining a shallow neutron porosity log for 7 freshwater evaluation as requested by the Commission. We'll 8 also be running wire line logs in the production hole, and the 9 third and fourth wells will also have wire line logs in the 10 production hole below the surface shoe. But for the most part, 11 we will be running MWD tools primarily as our primary data 12 gathering tool. 13 I guess with that short overview, that ends my - 14 testimony, unless there are any questions. 15 COMMISSIONER SEAMOUNT: Thank you, Mr. 16 Brockway. 17 MR. STRAMP: Okay. This is Ryan Stramp again. 18 I'm going to pick up the testimony now. I assume I'm still 19 sworn in before, or do I need to do something? 20 COMMISSIONER SEAMOUNT: Right. 21 MR. STRAMP: Okay. I'm going to spend just a 22 few minutes, and in the interest of time since it's getting 23 relatively close to lunch, I'm going to try to hit the 24 highlights on these. Please stop me or ask any questions as we 25 go, but in the absence of that, I'm going to hit the highest -. MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth A venue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 58 .) .) · 1 high points. 2 I'm going to talk about facilities a little bit. I've 3 hit this before. The main aspects of that are a gravel road 4 and a pad. The road and pipeline are each - - are all about ten 5 miles long. We cross four drainages along the way that require 6 bridges, pipelines, including a twenty-four inch production 7 line, and two injection lines, overhead power lines, and then 8 one drill site at the end of it. 9 The next slide I think is a map showing a little bit of 10 the topography. Apologize for the quality of the reproduction 11 but here's the southernmost Tarn drill site, Drill Site 2N. 12 Here's our new drill site, Drill Site 2P, by the way is what 13 we're calling the Meltwater drill site,and the road route and · 14 pipeline route paralleling it. 15 Slide 52 is a schematic showing a little bit more 16 detail on the pipeline installation. I was talking to Mike 17 Katowski (ph) during break, you know, this really is one of the 18 key facets of this project is it's a long way back to CPF2, and 19 we were unsure early on if, you know, we could expect to flow 20 all that distance back to CPF2 with just pipelines, and our 21 simulation efforts suggest that with this pipeline ins'tallation 22 that includes a twenty-four inch production line all the way 23 from 2D to 2N, and then we also at the same time installed a 24 new twenty-four inch production line loop from the 2N Tarn 25 drill site all the way back to this point, back close to CPF2, · MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 59 e) e) . 1 that this will allow us to flow the majority of the wells 2 naturally and with our -- help of artificial lift be able to 3 produce all the wells at a long distance back to CPF2. We also 4 see the MI line and water injection lines that will tie in to 5 the infrastructure at the Tarn drill site. 6 The on pad facilities consist of trunk and lateral well 7 manifolding system, very similar to what we installed at Tarn. 8 The lateral or the trunks will include a production trunk, a 9 test trunk, water injection, miscible injectant trunks. The 10 wellhead spacing will be twenty feet, minimum well to well. 11 We're going to install a conventional well test separator at 12 Meltwater. This is a change from Tarn. At Tarn, we used 13 Accuflow test equipment. You know, we still believe that IIÞ' 14 Accuflow can and does give reliable accurate well tests. 15 However, we feel like after our experience with Tarn that, you 16 know, there's an operating and maintenance cost associated with 17 that that is higher than what we can achieve with a 18 conventional test separator. So, that's why we're going this 19 route. We will have the ability to remotely switch wells in 20 and out of test, as well as control the choke settings on the 21 injectors and the producers. There will be an ESD skid to be 22 able to, you know, shut in the drill site remotely, as well as 23 a small electrical control room. 24 This is a -- slide 54 is a schematic of the pad at 25 drill site 2P. This is the row of wells. We've talked . MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 60 · · · e) e) 1 previously that we expect to drill approximately twenty-six 2 wells, although the drill site is sized to handle roughly twice 3 that many wells, ultimately. The trunks of the trunk and 4 lateral manifold -- or trunk and lateral system will be running 5 along this pipe rack. We have the facilities located here at 6 this end of the pad, and, you know, there really is not a lot 7 there. There's the small control room, the test separator. We 8 will have a small heater for heating the flows before they go 9 onto test, the ESD skid, and also pigging, a pigging module. 10 So, it's a fairly bare bones drill site. 11 A little bit more about well testing. We mentioned 12 it's going to be a conventional vessel. It will be designed to 13 separate gas and liquid only. The metering devices will be the 14 same metering devices as is the standard throughout the rest of 15 the Kuparuk Field. We'll use a micro motion mask flow meter 16 for total liquid measurement, phase dynamics meter to be able 17 to discern how much of that total liquid stream is water versus 18 oil, and vortex shedding meters for gas. 19 This is our proposed rule 7, which has to do with the 20 commingling of fluids from different reservoirs on the surface. 21 We would request that this rule specifically allow th~' 22 commingling of the Meltwater fluids with other produced fluids 23 from the Greater Kuparuk Area. We have a change to the 24 production allocation methodology that has been under 25 discussion for several months. Initially, it was brought up by MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 61 . .' . .) . 1 the Alaska Department of Revenue with involvement from the 2 Department of Natural Resources and AOGCC, and this stemmed 3 from the Department of Revenue's concern about possibly -- 4 well, it's related to the fact that the satellite fields at 5 Kuparuk and the other Prudhoe, as well, oftentimes have a 6 lower severance tax rate than the main fields do. And the 7 Department of Revenue wants to be very sure as we all do that 8 production allocation is done as fairly and accurately as 9 possible to ensure that the barrels are appropriately taxed 10 from a severance tax standpoint. And we came up with this new 11 scheme that instead of having a allocation factor of one, and 12 this allocation factor is basically how you adjust the well 13 test estimated production to make it match the actual meter 14 production from the field, instead of assuming that the 15 satellite fields all have an allocation factor of one, which 16 has been the case for West Sag, Tabasco, and Tarn so far, this 17 new scheme, and I'll have a slide that talks about this in a 18 moment, has all those -- all the satellite fìelds plus the main 19 Kuparuk Field basically all floating on a spe- -- on a 20 allocation factor month to month. There's no preprescribed 21 allocation factor of one point over the satellites anymore. 22 I'll talk about that in a minute. I know that sounded very 23 confusing. Hopefully, I'll clear it up. The more 24 straightforward part of this is that we intend to continue the 25 standard of the minimum of two well tests per month, and, of MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 62 · · · e) .) 1 course, monthly reports of allocation and test data. So, the 2 next slide hopefully I'll -- will help me explain a little bit 3 more about the allocation factor. 4 Again, this is new, and one of the terms that's used to 5 describe it is a floating or a float-float system, and that's 6 opposed to the old system, which had a prescribed allocation 7 factor of one for all satellites. In this new system, you 8 would calculate an overall allocation factor for Kuparuk 9 participating area, plus all of the existing satellite fields, 10 and so long as that calculated.allocation factor was less than 11 1.02, all of the PAs involved would have that same allocation 12 factor. If" however, that allocation factor is calculated to 13 be greater than 1.02, and this is a relatively arbitrary number 14 and I'll talk in a minute about why this is here, but it is 15 calculated to be greater than 1.02, but in the allocation 16 factor for all the satellites would be set at that 1.,02 level, 17 and that would result in some additional residual as yet 18 unallocated production that would be shifted to the KPA. And 19 the Department of Revenue's goal here I believe is to minimize 20 the chance of any barrels that should have been counted as 21 Kuparuk production being counted as satellite productión at a 22 lower severance tax rate. And they feel and we feel, as well, 23 the that this system will place emphasis on Phillips as the 24 operator to keep the well test systems tuned up and operating 25 as close to an allocation factor of one as possible, and help MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 63 e> e) . 1 us have the highest quality overall well tests that we can 2 attain. So, if there are questions about that, it's a 3 confusing topic, I know, but -- and it still is a bit of an 4 open topic although we're very close to coming to closure on 5 that with all the involved parties. 6 COMMISSIONER HEUSSER: Ryan, I have a..... 7 MR. STRAMP: Yeah. 8 COMMISSIONER HEUSSER: . . . . . couple of 9 questions. 10 MR. STRAMP: Okay. 11 COMMISSIONER HEUSSER: Just to make sure I 12 heard you correctly, basically, Kuparuk and all the satellites 13 are going to be thrown into the same pot? . 14 MR. STRAMP: For calculating allocation factor. 15 Severance tax-wise, they still will have their separate 16 severance tax status, and be taxed at their own severance tax 17 rates, but for calculating every month how much production is 18 attributable to the Kuparuk PA versus the TabascoPA versus the 19 Tarn PA versus Meltwater, this allocation factor scheme that 20 I've talked about will be a change from the way it's happened 21 in the past. 22 COMMISSIONER HEUSSER: Okay. So, you don't 23 even though this production is actually going to be processed 24 through CPF2, all of Kuparuk and all of the satellites are 25 going to enter into the calculation of the factor? e MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 64 · · 14 15 16 17 18 19 20 · e) e 1 MR. STRAMP: Yeah. Due to the way that the 2 Kuparuk Field is set up, and it's really because of the fact 3 that CPF3 contributes production of both CPFl and CPF2, there's 4 no single good master meter that you can say that -- or you 5 can't say that just because Meltwater produces to CPF2, that 6 you can look at CPF2 sales meter and say that that's somehow a 7 master meter for all of CPF2 because there's some CPF3 8 production that's in there, as well, so you have to look at the 9 field as a whole, and this is as straightforward a system as 10 we've been able to come up with to do that. 11 COMMISSIONER HEUSSER: Now, I heard you say 12 that 1.02 is arbitrary. Were you going to talk a little bit 13 more about that? MR. STRAMP: Yes, I can. It's -- the Department of Revenue requested that there be some upper limit to what the floating allocation factor can float to, and I guess as an example, if a given satellite, for instance, if the well test based estimate of production was that the satellite for any given month made 1,000 barrels a day, for actual monetary purposes, if you had an allocation factor of 1.02, you 21 would actually take that 1,000 barrels a day and multiply it by' 22 1.02, so you would have a number that was slightly bigger than 23 1,000 barrels a day that would actually be the value that taxes 24 would be paid on, for instance. And the Department of 25 Revenue's concern as I understand it is that they want to MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 65 e) e) . 1 minimize the chance of a satellite which typically is being 2 taxed at a much lower severance tax rate having its production 3 volume inflated to a larger volume than it might actually be. 4 So, they wanted to put a cap so that if it -- if for some 5 reason you calculated -- and it would never happen, but if you' 6 calculated a very, very large allocation factor, large in terms 7 of greater than one, that the operator would have some reason 8 to figure out, well, you know, why is that. You know, there's 9 something wrong if you calculate this to, you know - - you know, 10 potentially, if you calculate a number that's much, much higher 11 (indiscernible - background noise) the operator should have 12 some impetus that identify the problem and fix it. And by 13 putting this cap, and, you know, there's no science about what IIÞ 14 it should be other than there is I think a -- let me back up a 15 little bit. If perfection is measured by an allocation factor 16 of 1.0, if everything was tuned up as perfect as you could get 17 it, you probably are going to get month to month a little bit - 18 - you know, one month a little bit higher, the next month a 19 little bit lower than 1.0, so we felt like that there probably 20 should be a little bit dead band in there such that there would 21 be, you know, little or no external influence to the $ystem 22 whenever it's just operating normally. But putting this cap in 23 there says that if it gets far enough away from one on the high 24 side, that the system does change, and it changes in a 25 direction that would be in the operator's interest probably to . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 66 e} e) . 1 identify any problems that exist and resolve them. 2 COMMISSIONER HEUSSER: Now - - so, that's for 3 severance tax purposes. Are you going to use the same factor 4 for reservoir management? 5 MR. STRAMP: Yes. And one of our goals was to 6 have just one set of books. It's challenging enough to keep 7 one good set of books much less one for severance tax and one 8 for royalty and one for production reporting, so our goal, yes, 9 is to have this be a single allocation algorithm that applies 10 for all purposes, royalty, severance tax, as well as production 11 reporting. And we feel like it will. Within the guidelines 12 that are outlined here, it will have negligible, if any, affect 13 we think on long term reporting of volumes. And our allocation .' 14 factory -- or factor history has that we look back at Kuparuk 15 is we very seldom have been above one at all. Typically, 16 we're, you know, .97 to .99 type numbers is where we typically 17 run. And so we, frankly, don't foresee the situation occurring 18 but if it does, there'll be rules to handle it. 19 COMMISSIONER HEUSSER: Thank you. 20 MR. STRAMP: Okay. Thank you. That's a 21 confusing issue. 22 A couple of other proposed rules, Rule 12" as stated 23 here has to do with how we would handle production anomalies or 24 proration events. Our first goal would be to attempt to cut 25 all pools by equal percentages. However, we would be asked to . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 67 It 12 13 II 14 15 16 17 18 19 20 21 22 . e) e) 1 take into account, you know, modifications to that to avoid any 2 equipment damage or significantly increased operating costs, 3 and that's fairly straightforward and similar to other rules 4 that are in place now. 5 And the last one, Rule 13, has to do with the ability 6 of the Commission to modify or amend pool rules in an 7 administrative fashion. 8 So, that I think is what we had prepared specific to 9 the pool rules testimony. Again, there are in all thirteen 10 rules that we've -- I think we did today. We've touched a 11 little bit on each of them as our suggestions. COMMISSIONER HEUSSER: Ryan, I find that I have one last question..... MR. STRAMP: Sure. COMMISSIONER HEUSSER: . . .. .on allocation. Now, I understand from a severance tax standpoint why you want to shoot for something around one, but if you're going to use this for reservoir management, too, and you end up being -- having an allocation factor of, what, you know, .98 or nine seven for months on end, isn't this going to affect the way you manage your reservoir? MR. STRAMP: The number -- you know, the 23 deviations that we're talking about from one are so small that 24 they're really within the range of meaSurement uncertainty we 25 feel on the well tests anyway. So, we're not concerned about - MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 68 . e) . 1 - you know, from that standpoint about conceptually having our 2 numbers off by, you know, two percent or one and a half 3 percent. I mean I don't know exactly, you know, what precision 4 we would attribute to typical well testing but it's not plus or 5 minus two percent I don't think. You know, it's so, we 6 think that there is -- you know, it's within the range of 7 uncertainty. Directionally, we do still feel that the testing 8 of the satellite fields due to the fact that, you know, there's 9 fewer wells. We've, you know, got newer, better equipment 10 associated with -- or newer equipment I should say associated 11 with the test facilities. In some cases we do have some more 12 sophisticated test equipment involved. We think directionally 13 that the testing of the satellites probably is incrementally . 14 more accurate than the testing of a typical Kuparuk well, but 15 how to blend the two together we don't have a perfect way to 16 do. We had erred or jointly, the agencies involved anyway had, 17 you know, started off by assuming an allocation factor of 1.0. 18 It basically assumes that the well test adjusted for up time 19 and down time 20 Kuparuk test. 21 good it is. for the satellites was perfect relative to the It's probably an overstatement in terms of how Saying that it's exactly the same as Kuparuk 22 probably is an overstatement of how bad it is. The right 23 answer is probably somewhere in between but that in between is 24 so narrow that we're not uncomfortable about going ahead and 25 letting it float. . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 69 . . . 1 COMMISSIONER HEUSSER: So, is it safe to say 2 that you've set an upper limit of 1.02 but you didn't feel the 3 need to set a lower limit because the allocation factors that - 9 10 11 12 13 . 14 . 4 - the historical allocation factors at Kuparuk have run between 5 .97 and .99 for years? 6 MR. STRAMP: Yeah. And there, you know, 7 probably had been some excursion somewhere outside that range 8 but they've been short term. And the Department of Revenue had a external consultant come in late in the year last year and take a look on site at our metering and allocation procedures, and one of the things that he came back with was that he felt like that, you know, the overall Greater Kuparuk Area allocation methodology was well within industry standards for and, in fact, he commended us as I recall for having it 15 run as well as it does. So, you know, we agree with that and 16 ,feel like that overall we're doing, you know, a job that meets 17 industry standards, if not exceeds it in terms of overall 18 accuracy of our testing and allocation. So, yes, we're 19 comfortable with it as representing good numbers to run the 20 field by. 21 COMMISSIONER SEAMOUNT: Mr. Stramp, dp' you have 22 any estimates of when you would be finished with the evaluation 23 of the Cairn? 24 MR. STRAMP: We're going to get some 25 significant insights here in just a couple months, and I mean MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 70 71 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 · MET ROC 0 U R T R E P 0 R TIN G, INC. 22 haven't -- you intend to evaluate Cairn and Bermuda separately, 23 but you don't have a plan, a method to do it yet? 24 MR. FRAZER: Well, the plan is the Cairn 25 location does not anticipate encountering Bermuda. We don't COMMISSIONER SEAMOUNT: Okay. So, yoµ' 21 20 discussed. 19 just delay completing the Bermuda is something we have not yet 18 injection and production logging packages, or whether it would 17 evaluation purposes. Now, whether that entails separate 16 have an evaluation dedicated strictly for the Cairn for 13 Where are first Cairn penetration of any significance is · 14 planned, there is no Bermuda being mapped at that location. If 15 we do find Bermuda pay at that location, we would, in fact, MR. FRAZER: Yeah, I'll take a stab at that. 12 MR. STRAMP: Do you guys want to..... 11 10 out what ,to allocate? 9 commingle then test? How would you do -- how would you figure 8 evaluate, are you going to evaluate separate from the Bermuda COMMISSIONER SEAMOUNT: How are you going to 7 MR. MOOTHART: Which would be July. 6 COMMISSIONER SEAMOUNT: Are you going to..... 5 4 interval, and evaluate it with our fifth well. MR. MOOTHART: We plan to penetrate that 3 2 be over soon. So, I..... 1 depending on the results of that, if they're negative, it could · . ). .) . . . e) e) 1 think that..... 2 COMMISSIONER SEAMOUNT: Uh-hum, right. 3 MR. FRAZER: . . . . . would - - so it'll be a simple 4 plan. We'll go in and we test it and the well represents 5 Cairn. If we are mistaken and there is Bermuda potential 6 there, it would depend on the size of the Bermuda potential 7 relative to the size of Cairn, and then we would develop a plan 8 for testing the zone separately at that time. 9 COMMISSIONER SEAMOUNT: Okay. I see by the map 10 that you -- that the Cairn and the Bermuda are aerially 11 isolated, and Mr. Stramp was saying that evaluation would 12 proceed very quickly on the Cairn. Do you have a well plan for 13 the Cairn? 14 MR. FRAZER: Yes, we do. 15 COMMISSIONER SEAMOUNT: Okay. 16 MR. MOOTHART: Our first penetration like I 17 mentioned was of the Cairn prospective interval is set for 18 our fifth well. And that's basically the best location right 19 out here. So, t's outside of what we currently map as our zero 20 edge for the Bermuda Interval, but there's still potential for 21 that, and it's hitting the heart of the Cairn trend, so it's 22 kind of a dual delineation well. And right now on the schedule 23 I think that's probably looking mid to late July. 24 COMMISSIONER HEUSSER: Would you use a similar 25 completion design, three and a half inch tubing? MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 72 73 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. to have deviations within the field. 25 24 communication between injector and producers. So, we do expect 23 patterns where that's just not possible due to non- 22 2,400, it would be 2,400. However, there will likely be 21 voidage, so on an overall basis, if the initial pressure is MR. FRAZER: Our target will be to net (ph) 20 19 via injection? 18 maintenance. What reservoir pressure are you going to maintain 17 have another question. We heard talk about reservoir pressure Okay. Thank you. 10 COMMISSIONER HEUSSER: 11 ask for extended confidentiality? 12 MR. MOOTHART: No. 13 COMMISSIONER HEUSSER: .- 14 COMMISSIONER SEAMOUNT: 15 questions before we proceed? 16 COMMISSIONER HEUSSER: Oh, I do. I lied. I do Are there any other So, you don't intend to 9 year from now. 8 drilled in May of 2000, so I think they get released about a 7 by the State for two years, I believe, and those wells were MR. MOOTHART: There's -- the well data is held 6 5 will continue to be considered confidential? 4 currently still under confidentiality. Any idea how long those 3 regarding the confidential information, the wells that are COMMISSIONER HEUSSER: I have a question 2 (Nods yes) MR. STRAMP: 1 . .) e) 74 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. 25 Phillips on this issue. 24 injection order. Again, my name is Ryan Stramp testifying for 23 flip -- we'll move into the testimony related to the area MR. STRAMP: Okay. Why don't you go ahead and 22 21 a little bit so -- at least. COMMISSIONER SEAMOUNT: Well, I need to starve 20 19 finish just before we starve to death. I believe we'll MR. STRAMP: Okay. Let's 18 17 continue on then until we starve to death? COMMISSIONER SEAMOUNT: Well, why don't we 16 15 we're flexible. 14 would be happy to continue on unless you choose otherwise, but MR. STRAMP: I ask you for your preference. We 13 12 recess, continue after lunch. 11 you guys the option if you want to continue now or take a COMMISSIONER SEAMOUNT: Okay. Well, we'll give 10 9 forty-five minutes to an hour I would guess. MR. STRAMP: Yeah. It could well be another 8 7 time do you estimate on this, on area injection order? 6 there are. Now I have a question. Do we want -- how much more COMMISSIONER SEAMOUNT: It doesn't look like 5 4 testimony focused on the area injection order to follow. 3 pool rules? We've got a separate packet of information and MR. STRAMP: Any other questions related to the 2 COMMISSIONER HEUSSER: Okay. Thank you. 1 . e) . .' . . "\ 1 e) . 1 As we read the regulation 20 - - AAC 25.402 (c) , we see 2 that there are fifteen requirements related to establishing an 3 area injection order. We hope to rely upon the testimony that 4 you've just heard on the pool rule hearing for -- before those, 5 and that leaves eleven more to talk a little bit about here, 6 specifically. You know, the -- from the pool rule discussion, 8 you know, we discussed how we're going to operate, develop and operate the field, the depth and name of the pool, how we're going to complete the wells, and what we see is the incremental 7 9 10 increase and ultimate recovery associated with recovery 11 process. And that leaves this list of items that we have yet 12 to discuss, and we hope to spend the next few minutes going 13 over these .to the satisfaction of the Commission. So, with . 14 that, Steve's going to take off again. 15 MR. MOOTHART: Okay. This map you've seen 16 before. It's the Bermuda and Cairn anticipated net pay contours 17 and what I want to show here is just that the proposed 18 injection area for Meltwater is coincident with the pool area. 19 Flip forward. 20 The operators and surface owners of the injection area, 21 the operator is Phillips Alaska, Incorporated, and th~' surface 22 owner is the State of Alaska. Just want to note that faxed 23 copies of the pool rules or the injection order were sent to 24 these operator and surface owner on March 12th. 25 Type log, you've seen this before. The injection area, . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 75 e .' . e) . ,) 1 again, is coincident with the vertical definition of the 2 Meltwater Pool, the top being T4.1 at 4,958 subsea tvd in 3 Meltwater North 2A, and the base of the injection area would be 4 in T2 at 5,297 feet subsea tvd, and includes both the Cairn and 5 Bermuda Intervals. 6 This is the Meltwater North 2A log again but just 7 showing the shallow interval of the well, the Bermuda· Interval. 8 T3 to T2 is down here at the bottom. This is to show that our 9 first prospective reservoir zone out here is the C80 or Tabasco 10 interval. And this was meant to show that the injection 11 interval in these Meltwater wells are separated from the C80 by 12 about 2,700, 2,800 feet of impermeable shale. Should also be 13 noted that out here at the Meltwater, the Tabasco C80, I don't 14 see any reservoir sands, but elsewhere on the western margin of 15 Kuparuk there are some. 16 Initial development plans do not include plans fora 17 Class II disposal well, but if future needs require one, we 18 have basically identified the Ivishak sandstone of the 19 Sadlerochit Group as being an interval for Class II injection. 20 This is shown in the Sinclair Colville well number 1 well. The 21 Ivishak is this interval down in here. This well, exploration' 22 well, is to the north and west. It's drilled along the western 23 margin of the Kuparuk Field. Seeing this well, we would expect 24 in the Meltwater area that the Ivishak is down around 8,500 25 feet deep, so it's considerably below the reservoir zone. We MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 76 .) c) . 1 would expect about sixty feet of sand that -- of greater than 2 fifteen percent porosity. These -- this well and all the other 3 Ivishak wells on the western side here have been deemed wet, as 4 well as up in the Sag River Formation. The Ivishak out in this 5 area is separated from the Kuparuk River Interval by at least 6 or approximately 1,800 feet of Kingak shale, so impermeable 7 shales, and then also by about 400 feet of the Sag River and 8 Shublik. 9 COMMISSIONER SEAMOUNT: Mr. Moothart? 10 MR. MOOTHART: Yeah. 11 COMMISSIONER SEAMOUNT: How much what did 12 you say the porosity was at the Ivishak? 13 .' 14 about sixty 15 16 17 18 MR. MOOTHART: We had -- in this well you have feet that's greater than fifteen percent. COMMISSIONER SEAMOUNT: Sixty feet that's..... MR. MOOTHART: Yeah. COMMISSIONER SEAMOUNT: ..... .greater than. .... MR. MOOTHART: Fifteen percent. 19 COMMISSIONER SEAMOUNT: .... .fifteen. It looks 20 like there's a lot more sand there than sixty feet. 21 MR. MOOTHART: Yeah. 22 COMMISSIONER SEAMOUNT: So, most of that's 23 pretty tight. Okay. 24 MR. MOOTHART: At Meltwater, I mentioned 25 earlier in the pool rules no water zones were encountered by . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 77 · · · . ) e) 1 Meltwater, or by the exploration wells at Meltwater. Connate 2 water was obtained from core plugs using a miscible extraction 3 process for analyzing that water. Chlorides were then measured 4 by ion chromatography. Chloride content of the Bermuda at 5 Meltwater range from twenty to 40,000 parts per million total 6 dissolve solids. The range in the chlorides is due to 7 diffusion of the chlorides by freshwater drilling fluids. As I 8 mentioned earlier, we're currently gathering a core with tracer 9 data to pin down that composition. 10 This plot is to start walking into the issue of aquifer 11 exemption. What I wanted to show here was the existing Greater 12 Kuparuk Area exemption zone here. Here's Alpine and its 13 aquifer exemption zone, and then the pool area for the 14 Meltwater here kind of tacked onto the south side of the 15 Kuparuk exemption area. Initial wells, while the let me 16 state Kuparukexemption area was granted by the EPA in 1984. 17 No porosity logs were gathered in the shallow holes of the 18 Meltwater North wells. What we want to talk about now is 19 saliniti~s, water salinities in the shallow portion, shallow 20 intervals out here. The wells specifically that I'm going to 21 talk about are Kalubik Number 1 up here, Arco Colvill.e' River 22 State here, and then two wells within the Tarn area, 2N-349, 23 and then also located very close to this 2N-30S, and then the 24 Cirque 2. All four of those five wells, all the wells except 25 for 2N-305 have shallow porosity logs so we're able to MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 78 . e . .) e) 1 calculate water salinities in the shallow intervals. 2 COMMISSIONER SEAMOUNT: What kind of porosity 3 logs are they? 4 MR. MOOTHART: Density and neutron. And 5 they're all wire lined, density and neutron. 6 COMMISSIONER SEAMOUNT: Thank you. 7 MR. MOOTHART: You'll note that two of the 8 wells are located outside of any existing aquifer exemption 9 zone, while the Tarn wells and Cirque 2 are within the Greater 10 Kuparuk exemption zone. 11 This is just a table listing the shallow interval. 12 Intervals within the shallow portion of the wells that appear 13 to be water bearing and some of their calculated salinities. 14 The technique for calculating these salinities is using the SP 15 and Rw apparent. These are denoted -- both these -- this 16 technique is denoted as the resistivity porosity or RP 17 technique in the EPA guideline document. Both using the SP and 18 Rw apparent are standard techniques within the industry. 19 Should be noted on this table that all the salinity or fluid 20 resistivity measurements have been corrected to 75 degrees 21 Fahrenheit for comparison technique. 22 The salinities measured are in NaCl or total dissolved 23 solids. And just step through these. Remember Kalubik 1 and 24 Colville River State 1 where wells outside of any current 25 aquifer exemption zone, permafrost as you move towards the MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 79 e) tP) · 1 coast, of course, gets a little deeper. Permafrost is at 1,510 2 and Kalubik, 1,360. Kalubik, we're looking at a water-bearing 3 sand from about 1,740 to 1,790 feet in depth, and the water 4 salinities for the two zones range from just over 5,000 parts 5 per million to 15,000 parts per million. Should be noted that 6 the hole is badly washed out, and that the SP measurement is 7 probably more representative. Colville River State Number 1, 8 permafrost is about 1,360 feet. There's a water-bearing sand 9 at 1,510 to 1,520 in depth, and in this well, our water 10 salinities are very high, even this close to the shallow and 11 this close to permafrost. The two measurements range from 12 about twenty to 28,000 parts per million. 13 Cirque 2,which is exploration well sitting kind of · 14 between Tarn and Meltwater, permafrost there is at 1,170. The 15 Rwa and Rwsp calculations should note we're looking at sand 16 between 1,440 and 1,460 at depth. In measurements that we get, 17 salinity measurements, range in Rwa from 2.5 Kppm to 5.4 Kppm. 18 It should also be noted that hydrates are known in this shallow 19 portion of this well. Remember, this well had the lot when it 20 was drilled. SP is probably more representative, although our 21 petrophysicist thinks it's still too low of a measure~ent. 22 Hard to -- you can't calculate the salinities in the presence 23 of -- accurately within the presence of hydrates because its 24 solid nature. 25 COMMISSIONER SEAMOUNT: Well, do you believe · MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 80 81 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. 22 sands present below that 2,400 foot depth to test that, though 23 measurements, estimates from the shales would suggest 24 salinities of 20,000 Kppm. 25 COMMISSIONER SEAMOUNT: In the 2N-349, you 21 salinity with -- below that depth. There are no appreciable 20 systematically below about 2,400 feet implying an increase in 19 noted that below this sand interval, LWD resistivity decreases 18 more representative of the two measurements. Should also be 17 got hydrates below permafrost, and that the Rwa is actually 16 SP is roughly 4.5 Kppm. Now, here, we also believe that we've Rw from the 15 calculations from logs, Rwa is 6.9 Kppm, and Rwa 14 water interval 1,905 to 1,915 subsea depth. Our salinity .' 13 2N-349 permafrost is about 1,310. We have a sand that we see, 12 Field it's interesting where we can measure the hydrates. Tarn 11 we'll check on that. I will show you at 2N-349 and in the Tarn 10 in that interval of that particular well. I will show you MR. MOOTHART: Don't -- I haven't looked at one 9 8_ on that sand, a gas reading? COMMISSIONER SEAMOUNT: Did you have a mud log 7 6 hydrates, I can't tell you. MR. MOOTHART: If that individual sand contains 5 4 that you use to determine if it's hydrate or not? COMMISSIONER SEAMOUNT: What are your criteria 3 MR. MOOTHART: Yeah. 2 1 that sand contains hydrates? . ~) &) . . . C) r) 1 might have said this already but are there sand -- additional 2 sands between 1,300 and 1,900 that show different log 3 characteristics? 4 MR. MOOTHART: Again, that we think are 5 hydrate-bearing, and that's what we'll go into now. 6 This is a plot of Rwa versus depth. What you see here 7 is at an Rwa. This is so, a little over one and a half you 8 would expect your salinity calculation to be about 3,000 Kppm 9 total dissolved solids. In 2N-349, that one sand that we 10· looked at, we see Rwa of about .8, and that comes to about that 11 6.9 Kppm. But here's base permafrost up in here. This is zone 12 that petrophysicists feels hydrate-bearing down to about 1,700 13 feet. And what you really want to focus in on are these blue 14 dots shown, and below that hydrate-bearing zone there's this 15 blue dot, trail of blue dots here at about 1,850. Here at 16 about 1,900, this is a sand that we did the calculations in, 17 and then there's a few blue dots down here at about 2,100 feet. 18 This sand right here is a tight streak. What the blue dots 19 represent are a low V shale content. This cross plot then is 20 color coded by beach shale, so you want to calculate a clean 21 sand. 22 This zone though it calculates low V shale is a tight 23 streak carbonate cemented. Like I mentioned, this is the sand 24 that we looked at here, and the next area that calculates any 25 type of low V shale is actually a pyrite cemented zone or MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 82 II It e e) e) 1 pyrite streak in the well. 2 You asked about hydrates. Our next plot is going to be 3 from 2N~305. This is a gas sample log that was taken in 2N-305 4 as part of a USGS study here last year on gas hydrates. And 5 2N-349 and 2N-305 are -- at this shallow interval are about 950 6 feet apart from one another. At the Bermuda Interval, they're 7 much further than that, but they're shallow in the hole. What 8 we -- what you see here are the gas measurements for Cl through 9 C4, actually up into C5, and up into C6, and what we see is at 10 about 1,300, a little under -- over 1,300, we see a strong Cl 11 peak here, and when you combine all the gas sampling, you see a 12 strong response just below the permafrost here. This is 13 associated with hydrate deposits. They had also made note of 14 some contamination of the shallow portion of the shallowest 15 portion of the hole that they thought was there, and an 16 interesting spike down around 2,400 that Tim Collett with the 17 USGS raised the question do we have hydrates even down that 18 far, that deep, below permafrost. 19 Next is -- slide is just another. 20 COMMISSIONER SEAMOUNT: Why would you 21 necessarily think that's hydrates other than it had ~ 'gas 22 shelf? I mean couldn't it be free gas? 23 MR. MOOTHART: Yeah. 24 COMMISSIONER SEAMOUNT: Okay. 25 MR. MOOTHART: It could be free gas in the MET ROC 0 V R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 83 c) ~) . 1 interval, too. There's nothing there that pointed to hydrates. 2 Next, this is just another plot from the same well, 3 again, showing gas sampling versus mud temperature and the 4 depth. Again, all I wanted to show was, again, righü below 5 permafrost we see the large increase in the gas presence of the 6 hydrates. 7 So, our conclusion to this is that we see no apparent 8 fresh water zones in the Meltwater area suitable for human 9 consumption, and that we would líke to apply for an aquifer 10 exemption for the Meltwater pool. And that's my portion of 11 this. Any further questions? 12 COMMISSIONER SEAMOUNT: Any questions? 13 e 14 Frazer. 15 16 Moothart. MR. MOOTHART: Then I'll turn it over to Lamont COMMISSIONER SEAMOUNT: Thank you, Mr. Mr. Frazer? 17 MR. FRAZER: Yes. What I'm first going to 18 cover is the injection data. And this is the injection data 19 showing the water composition coming from CPF2. And this is a 20 typical sample that was obtained during calendar year 2000. 21 There is a written copy of this in the area injection order 22 written testimony. 23 With regard to gas compositions, this is, again, 24 provided in the written testimony, but it shows the lean gas 25 and MI compositions coming from CPF2 during calendar year 2000, . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 84 C) ..) . 1 and this is an average on an average basis. 2 COMMISSIONER SEAMOUNT: Are you done? 3 MR. FRAZER: No. 4 COMMISSIONER SEAMOUNT: Sorry. 5 MR. FRAZER: One last slide. 6 COMMISSIONER SEAMOUNT: We -- sorry. We had to 7 take a little break for a second. 8 MR. FRAZER: That's all right. On this last 9 slide I'm going to talk about estimated injection pressures, 10 injection zone confinement, and the conditions of the existing 11 penetrations. With regard to our estimate injection pressures, 12 we expect water pressures -- injection pressures to range from 13 1,600 to 2,600 psi. The best estimate is that we'll have about . 14 a 2,00 psi water injection pressure based on our hydraulic 15 modeling. 16 With regard to gas injection pressures, we expect them 17 to range between twenty-six and 3,600 psi. And, again, based 18 on hydraulic modeling, our best estimate is 2,800 psi is the MI 19 injection pressure we'll see on site. 20 With regard to injection confinement, what we did is we 21 used a model stim plan that relies on a Nolte Smith ~ódeling 22 technique to predict fracture height, and that modeling 23 technique assumes a single fracture plan, which is a worst case 24 scenario from a height growth standpoint. If there was more 25 than one fracture plane, height growth would be reduced. We . MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 85 . .' 14 15 16 17 18 19 20 21 22 23 . e) .) 1 looked at an MI injection case at 15 million a day, which is 2 the highest end that we would expect to inject MI at, ·and there 3 was no appreciable height growth whatsoever. We then looked at 4 water injection at an injection rate of 10,000 barrels of water 5 per day, and we saw only ten feet -- approximately ten feet of 6 upward height growth. We then looked at a prop fracture height 7 assuming some worse case prop fracture assumptions. We assume 8 we had a seventy foot interval of gross thickness, half of 9 which was pay, nominally thirty-five feet of pay, and we pumped 10 a 200,000 pound job. Under that scenario, we got a fracture -- 11 upward fracture height of about 200 feet. This is well within 12 the confining zones that Steve Moothart had showed earlier. 13 With regard to the mechanical condition of our existing exploratory well penetrations, they have all been P and A'd in accordance with AOGCC regulations, and we have cut the casing strings off three feet below ground level, again, in accordance with regulations. And that concludes my testimony. Are there any questions? COMMISSIONER SEAMOUNT: Do you have any 200,000 pound frac jobs planned? MR. FRAZER: Yes, we do. COMMISSIONER SEAMOUNT: Okay. MR. FRAZER: Two hundred thousand pounds is a 24 fairly typical type fracture stimulation. And thirty-five feet 25 of net pay and seventy feet of gross interval is about the MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 86 87 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 V R T R E P 0 R TIN G, INC. necessary to proceed with implementation of our EOR project. but, you know, we want to ensure that we have all the approvals exemption is kind of the further guarantee beyond that, that so I mean our -- we -- but as I understand it, the aquifer don't see any fresh water zones, and do not -- as we ,t'estified, 20 me if you need an aquifer exemption to do that. I mean we 19 requesting the area injection order, and it's a bit unclear to MR. STRAMP: Yeah. As I see it, we're 17 rules? 16 the aquifer exemption later or I guess included within pool COMMISSIONER SEAMOUNT: Are you applying for 14 things. 13 We got done faster than I thought. Hunger can do amazing MR. STRAMP: I guess I made a liar out of me. 11 questions? COMMISSIONER SEAMOUNT: Are there any other COMMISSIONER HEUSSER: Okay. rates. well that has the tubing size sufficiently to approach those at 10,000 barrels of water per day, and we'll only have one MR. FRAZER: The water injection rate was run scenario water injection rate? COMMISSIONER HEUSSER: What was the worst case than that is likely uneconomic. worst type of conditions we would go after. Anything thinner 4r) .) . 25 24 23 22 21 18 15 . 12 10 . 1 2 3 4 5 6 7 8 9 88 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 MET ROC 0 U R T R E P 0 R TIN G, INC. MR. MOOTHART: No. 25 24 injecting into those zones? 23 planning on -- I guess I missed that. Are you planning on 22 COMMISSIONER SEAMOUNT: But they're not 21 exemption requires review by EPA before it can be approved. COMMISSIONER TAYLOR: Okay. The aquifer 20 19 exemption then. 18 apologize for misstating it. We are applying for the aquifer MR. STRAMP: Okay. So, I retract our 17 MR. MOOTHART: Right. 16 MR. STRAMP: So, we're in the middle case then. 15 14 about, you don't have to have an exemption for. 13 exemption, and anything un- -- over ten you don't have to worry you could apply for an 12 to ten you applied for an exempt 11 anything with. You know, it had to be protected. From three 10 been kind of put forth was anything under 3,000 you couldn't do 9 per million, but if I remember right, the guidelines that have MR. MOOTHART: We've seen under 10,000 parts 8 7 that shows what that water. . . . . 6 anything under 10,000 parts per million? Do you have any data COMMISSIONER TAYLOR: So, you haven't seen 5 MR. STRAMP: Yes, I believe so. 4 3 drinking water the way our regulation defines fresh water? 2 fresh water, the way EPA defines underground sources of COMMISSIONER TAYLOR: Are you using the term, 1 ,,) .) . it e 89 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 . MET ROC 0 U R T R E P 0 R TIN G, INC. COMMISSIONER SEAMOUNT: It's..... 25 COMMISSIONER TAYLOR: Well, that's not clear. 24 23 one, right, for this injection program? COMMISSIONER SEAMOUNT: So, they don't need 22 21 know, where we're 20 to 40,000 Kppm. MR. MOOTHART: That's our connate waters, you 20 19 we're concern- -- we're not concern- --..... COMMISSIONER SEAMOUNT: I think that's what 18 MR. MOOTHART: Yeah. 17 MR. MOOTHART: Oh, yeah. COMMISSIONER TAYLOR: Okay. 16 15 .' 14 that injection zone? COMMISSIONER TAYLOR: Do you have data as to 13 MR. MOOTHART: Pardon? 12 11 to that injection zone that you could provide? COMMISSIONER TAYLOR: And do you have data as MR. STRAMP: No. . 1 2 3 the Bermuda? 4 5 6 7 those zones. 8 9 feet. 10 MR. MOOTHART: The injection zone is 4,000 MR. STRAMP: Right. MR. MOOTHART: Right. MR. STRAMP: We intend to remain isolated from COMMISSIONER SEAMOUNT: Your injection zone is .) C) · · · . ') 4r) 1 MR. STRAMP: Maybe I'm not as stupid as I 2 thought. 3 COMMISSIONER SEAMOUNT: I think what you're 4 you have to do an evaluation of the zone you want to inject in, 5 am I -- no, I'm not correct. Okay. 6 COMMISSIONER TAYLOR: It also deals with what 7 other requirements they would need an exemption from, so maybe 8 what we can do is contact Mr. Stramp with any additional 9 questions we have. 10 MR. STRAMP: Yeah, that would be fine. I don't 11 know if we have to leave the record open or what we have to do, 12 but, certainly, we are very interested in getting this as 13 resolved as we can. 14 COMMISSIONER SEAMOUNT: Okay. We'll get it 15 straightened out. Do we have to leave the record open? 16 COMMISSIONER TAYLOR: Mr. Stramp, why don't we 17 leave it that we will follow up with a letter. If we request 18 additional information from you, we'll put it in writing. That 19 way, it will keep the record open to receive whatever 20 additional information we might need. 21 MR. STRAMP: Whatever works for you. 22 COMMISSIONER TAYLOR: Okay. 23 COMMISSIONER SEAMOUNT: Any other questions? 24 Shall we close? 25 MR. STRAMP: We appreciate the opportunity to MET ROC 0 U R T R E P 0 R TIN G, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 90 91 745 West Fourth Avenue, Suite 425 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 13 .' 14 12 11 10 9 END OF PROCEEDINGS 8 (Off record 12:20 p.m.) 7 6 on your project, and I guess we can close now. Off the record. 5 outstanding and interesting presentation. Wish you good luck COMMISSIONER SEAMOUNT: Thank you for a very 4 COMMISSIONER TAYLOR: Thank you. 3 2 your patience and sitting through it all, and..... 1 present this information to you this morning, and thank you for . .) " é) V j 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • CERTI F I CATE UNITED STATES OF AMERICA) ) ss. STATE OF ALASKA ) I, Laura Ferro, Notary Public in and for the State of Alaska, and Reporter for Metro Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Public, Hearing was taken before Sharon Gaunt on the 7th day of May, 2001, commencing at the hour of 9:06 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 333 West Seventh Avenue, Suite 100, Anchorage, Alaska; That the meeting was transcribed by myself to the best of my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this llth day of May 2001. Notary Public 'n r k o u c i .and for Alaska Y My commission expires: 06/03/01 METRO COURT REPORTING, INC. 745 West Fourth Avenue, Suite 425 Anchorage, Alaska 99501 (907) 276-3876 #6 ) " " ALASKA OIL AND GAS CONSERVATION COMMISSION Date: /l?llv 7, 2 Of/ I Time c¡ á n? MEETING - Subiect /Jlé' /-1 ú"./ ~r- 4~a I'" / "n'1 NAME - AFFILIATION (PLEASE PRINT) ~e- WtooThtv--1- L ~çt".e>'\\.",\: ~ Ç' q.::t. e f'" ~r¡ø... L.cJ ... ¥1 fY «. J)q~llt: I -rtf£tU-y 11/!.L-ß/V ÞHM i>Al.MIQ ¡;;-v u.rru~'tL 'h/l\ S~,rnp 'fAO ~7 j 61< ad:.. w tfX'i 1<('í5':,~ Nf"j~ ~k\roC-.- b4-v ,¿50 1 <:' 'M A/\ (Ã v Þ L-l'ff) U /t1tKe Rotbwsk,,-- Sf...ð fJ ? C?d ¡Þ\ ¿;( c... TELEPHONE o/h,1\,P,s A-\Ç(.ð r~ .:í,.¡c... ~GS- - 696 S- ~\-\~\\ -\,~ ~ A"'~ ~o... ) ~.r\(.._'.. .;z\o.::? - -'\5.5 c P~,' lL'r~ A-k rJlo'ñ ---10 ;/)~ ,Ph, / /15 .A-It:t->lca.. &'c. ¡z ~)" b z ~ò G;60/ ~~/.c../-L- (~t)AlS . 333 -ff80 ~I-hu..tes kAS5!.A,:t~ ~V:<;".... J:\Y J Phll/,pç' ~ It!Jtc.¡-L:n t . 2,&5 ~b t;¿lG ph, ((,f~ AI451ut '[P/¿.. 2bS -'-/13::- ~NA-) ~~·30~~ /l~ 7'f3-1¿2-~ 7-,7'1 '-f7 OJ f)No/tJo¿,e;; pIA I lip) #(Î41zc., I btC ~~ r- ee/;;J... U1-4yll! #5 ) ) PHilliPS Alaska, Inc. A Subsidiary of PHilLIPS PETROLEUM COMPANY Post Office Box 1 00360 700 G Street Anchorage, Alaska 99510 Telephone 907 265-6806 Ryan Stramp, Meltwater Coordinator RECEIVED MAY 07 2001 Alaska Oil & Gas Cons. Commission Anchorage May 7,2001 Ms. Julie Heusser, Mr. Dan Seamount and Ms. Cammy Taylor Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Re: Meltwater Area Injection Order 20 AAC 25.402 Dear Commissioners: Phillips Alaska, Inc. (PAl) is pursing development of the Meltwater Reservoir. PAl initially briefed the Commission on Meltwater during a January 30, 2001 meeting. PAl subsequently submitted an application to the Commission on March 12, 2001 to conduct an enhanced recovery operation involving MW AG (Le., alternating water and miscible gas injection), consistent with 20 AAC 25.402 (a). Approval of the application would permit these operations to be conducted within the proposed Meltwater Pool. This letter provides updated technical details supporting the original application. The following attachments are submitted pursuant to 20 AAC 25.402 (c): 1. Plat with location of all existing wells that penetrate the injection zone within one- quarter mile of the area covered by this application. 2. List of operators and surface owners within one-quarter mile of the proposed injection operations. 3. Affidavit showing that operators and surface owners within one-quarter mile of the area affected by the Meltwater Area Injection Order were provided a copy of the March 12 application. 4. Full description of the proposed operation. 5. Description, depth, and name of the pool to be affected. 6. Description of the formation into which fluids are to be injected and the associated confining zones. 7. Type well log. 8. Casing description and proposed method for testing injection well casing. 9. Injection fluid data. 10. Estimated injection pressures. 11. Evidence and data to support a commission finding that injection wells will not initiate or propagate fractures through the overlying strata. 12. Analysis of the water within the formation. Phillips Alaska, Inc, is a subsidiary of Phillips Petroleum Company ') ) 13. Reference to offset freshwater exemptions issued under 20 AAC 25.440 and data suggesting no freshwater aquifers in the region. 14. Incremental increase in ultimate hydrocarbon recovery. 15. Mechanical condition of each well that has penetrated the proposed injection zone within a one-quarter mile radius of the Meltwater Oil Pool. I appreciate your work on the Meltwater Area Injection Order application and would be happy to answer any related questions. I can be reached at 265-6268 or rstramp@ ppco.com via email. Sincerely, 11j~~~~ RUn Stramp Meltwater Coordinator cc: Mike Kotowski Meltwater Area Injection Order Page 2/32 ') ) Meltwater Area Injection Order Attachment 1 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Iniection Zone The attached map (Attachment 1 A) shows all existing wells that penetrate the injection zone in the proposed injection area. The map also shows Meltwater Reservoir seismic anomalies and the proposed Kuparuk River Unit expansion area. Although the exact acreage of the expansion has not yet been finalized, this map shows its largest possible extent based on current expansion efforts. In addition, the map shows Meltwater development wells (with their expected initial service) planned to be drilled during 2001 and 2002 and Meltwater exploratory well penetrations. Initial well location and service plans will likely change as net pay and well performance data are gathered. The total number, type and locations of wells ultimately drilled into the Meltwater Pool will also be a function of net pay and well performance data. Since Meltwater Reservoir distribution is stratigraphically controlled and sand accumulations are localized, sand continuity is expected to be difficult to predict. Producer/Injector interactions will likely be difficult to predict in the absence of field data. Development plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injection service as necessary in order to provide pressure support and minimize injectant cycling. Hence, to as large of an extent as possible, plans are to let reservoir performance be a guide in optimizing pattern configurations. Although initial development plans do not include a Class II disposal well, future needs may eventually require one. The Ivishak Sandstone of the Sadlerochit Group has been selected, if needed. This zone is expected to have at least 60 feet of sandstone with porosities greater than 15% in the vicinity of the Meltwater Participating Area. The Ivishak depth is expected to be approximately 8500 feet subsea. Several exploration wells have been drilled to this horizon in the vicinity of the Meltwater Participating Area, in particular, the Union Kookpuk, Union Itkillik River and Sinclair Colville wells. The Ivishak Sandstone was wet in each of these wells and is therefore also expected to be wet in the vicinity of the Meltwater Participating Area wells (see Sinclair Colville log section, Attachment 11 c). The Ivishak Sandstone, as well as the overlying Shublik Formation and Sag R. Sandstone, was wet in each of these wells. This zone is therefore also expected to be wet in the vicinity of the Meltwater Participating Area. The Ivishak Sandstone is separated from the overlying Kuparuk River Formation by approximately 1800 feet of shales of the Kingak Formation, as well as approximately 400 feet of Shublik and Sag River Sandstone. Meltwater Area Injection Order Page 3/32 Attachment 1 A Net Pay Map with Planned Wells eltwater Bermu a Int rval et Pay Map PLANNED BERMUDA INTERVAL WELLS PRIXJI..':ER. INJR.'TQR J. PLANNED CA.IRN INTEFi\lA.L WELLS PROD'JCER . INJEC1CR Meltwater Area Injection Order Page 4/32 ~) ) Meltwater Area Injection Order Attachment 2 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Iniection Operations Operator: Phillips Alaska, Inc. Attention: Dan Kruse A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owner: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 Meltwater Area Injection Order Page 5/32 ) Meltwater Area Injection Order Attachment 3 20 AAC 25.402 (c){3) Affidavit of Ryan L. Stramp Regarding Notice to Surface Owners Ryan L. Stramp, on oath, deposes and says: 1. I am the Meltwater Coordinator at Phillips Alaska, Inc., the designated operator of the Kuparuk River Unit (which will include the Meltwater Pool). 2. On March 12, 2001, I caused copies of the Area Injection Order Application to be provided to the surface owner and operator of all land within a quarter mile of the unit as listed below: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 Phillips Alaska, Inc. Attention: Dan Kruse A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 ~ 7<ya~~ ...... STATE OF ALASKA ) ) ssP THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this 12th day of March, 2001, ?{cd:J,u..v A:. ù....D~,,~ NU I ARY ~U[UG IN À~LJ¡:-OK ALA~KA \\\l((({{/((( \.\.\ ,I ~ E. Ho (/"/: \\: n.."'\ . ' ' , '. <.< ~ \.."~'),.v. ---' .ar.,..- .:;.- ~ -.' 0 TAb' , \I~~ .:::- 'q": ~ ~ .:.~--;' '-~. --- .......= ~*: PUBLiC ;z~ ::. ", " *- ~ . --- . ~ -::". .' '" ....." ~p).. . . hoc " . ,', "."'~. . . . . .....l~ :\' ···;'"T'F'o-"" ~~\:\ ., '.. . ~ ,......t'. '\ '\ //jJ},';j)j\ My Commission Expires: ~ t \ SI"2ëo ( Meltwater Area Injection Order Page 6/32 ) Meltwater Area Injection Order Attachment 4 20 AAC 25.402 (c)(4) Description of the Proposed Operation The Meltwater Area Injection Order is needed to develop the Meltwater Reservoir. The expected scope of the current development project involves drilling approximately 26 wells to develop 52 MMBO associated with an estimated 132 MMBO original oil in place (OOIP) seen by existing exploratory wells in the Bermuda Interval of the Meltwater Reservoir. Although Attachment 1 A shows 41 penetrations, this is considered an upside case. Field Development Development wells will be drilled from a single new drill site. Initial development drilling operations are planned to start during the second quarter of this year, The drilling program will initially focus on developing the main portion of the reservoir and testing the periphery, Well performance data and improved seismic calibrations acquired from the initial development wells will help guide the extent of the overall development drilling program, Exploratory drilling targeting other zones within the Meltwater Reservoir will be conducted concurrently with development drilling operations, Successful exploratory drilling results could alter existing plans by (1) changing the location and target interval of the initial development wells and (2) expanding the scope of the project to include additional wells, An expanded project scope would likely involve additional development drilling phases and may require an areal expansion of the proffered Meltwater Area I njection Order. Recovery Mechanism Initially employing an MW AG recovery process, which consists of alternating cycles of water and MI, is a key aspect of the planned development. Following are the main reasons for the 1, Numerical simulation indicates that MW AG provides higher recoveries than any other competing recovery process (Le" primary drainage, waterflood, miscible gas flood, and lean gas flood), For example, simulation results suggest that an MW AG process, with a 20% cumulative hydrocarbon pore volume slug of injected miscible gas, would provide an incremental recovery of 90/0 001 P compared to a waterflood process, 2, Enriched natural gas used at Kuparuk is miscible with Meltwater fluids at reservoir conditions. (Henceforth in this document, enriched natural gas will be referred to as "MI" for Miscible Injectant.) This is supported by slim tube simulation results and is consistent with actual slim tube experiments run on Tarn crude. (Given that the composition of Meltwater and Tarn crudes are very similar, they should behave in a similar fashion from a phase behavior and fluid displacement standpoint.) Meltwater Area Injection Order Page 7/32 ') ) 3. Greater Kuparuk Area (GKA) MI is currently piped to offset Tarn Drill Site 2N and is transportable to Meltwater for a relatively small premium, 4, Initially pursing MW AG is imperative if this EOR process is to be employed, Meltwater's MI supply is dependent on existing west-end GKA infrastructure, The MW AG floods in this part of the GKA are relatively mature, Delaying implementation of MW AG at Meltwater would therefore jeopardize this project's EOR reserves, as critical GKA infrastructure may not be available in the future to transport MI. (Other potential uses of the GKA MI distribution system include de- bottlenecking production/injection lines and providing high pressure lift gas), After the cumulative target slug size of MI has been injected into the formation, pressure support will be maintained with water injection. Current plans are to eventually inject lean gas into the reservoir to help recover light liquid hydrocarbons (used to manufacture MI) that will be trapped in the reservoir by the MWAG process, Injectant Sources The miscible injectant employed at Meltwater will initially be the same injectant as that currently used at Tarn and the Kuparuk River Unit Large Scale EOR Project. This injectant is manufactured at Kuparuk's CPF-1 and CPF-2 by blending lean gas from the Kuparuk River Unit's production facilities with light hydrocarbon liquid streams from the Prudhoe Bay Unit and Kuparuk River Unit. The light liquid hydrocarbons from the Prudhoe Bay Unit are NGLs from the CGF. The light liquid hydrocarbons from the Kuparuk River Unit consist of scrubber liquids from artificial lift gas compression systems at CPF-1 and CPF-2, NGLs from CPF-1 and naphtha from the Topping Plant. During the flood, there is a possibility that Meltwater produced gas may be blended with Kuparuk River Unit MI to generate a lighter MI blend customized for the Meltwater Reservoir pressure and oil properties, Slim tube simulation results and slim tube experiments on similar (Tarn) crude indicate that Kuparuk MI is richer than needed to achieve miscibility with Meltwater oil at reservoir pressure (2400 psig in the Meltwater #1 well), After the cumulative target slug size of MI has been injected into the formation, pressure support will be maintained with water injection, Current plans are to eventually inject lean gas into the reservoir to help recover light liquid hydrocarbons (used to manufacture MI) that will be trapped in the reservoir by the MWAG process, The source of the lean gas will be Kuparuk River Unit's CPF-2, Potential gas accumulations in the area will also be considered as possible supplemental sources, Meltwater Area Injection Order Page 8/32 ') ') ) Fluid and Cost Allocation Meltwater production will be commingled with Tarn and Kuparuk production in surface facilities prior to final processing and ultimate custody transfer in accordance with the Meltwater Pool Rules (currently being developed), The Greater Kuparuk Area Alignment Agreement, which set new tract ownership and facility sharing terms in the Meltwater area, will help govern business issues associated with sharing infrastructure, A portion of the Meltwater accumulation extends outside the existing GKA onto a PAI/BP lease (see Attachment 4A), All GKA owners, except Exxon-Mobil (with a .3648% GKA working interest), have agreed to buy interest in the lease. Mobil heritage interest was proportionately split between Phillips and BP based on an estimate that 40.6042% of total Meltwater net sand volume is located on this lease, No future production interest adjustments will be made, The resulting Meltwater cost and production working interests, pending approval of the Supplemental Provisions, are as follows: Cost Production Phillips Alaska, Inc, 0,55957929 0,55379056 BP 0,39754111 0.39342864 U nocal 0,03960480 0,04950600 Mobil 0,00218880 0,00218880 Chevron 0.00108600 0,00108600 Total 1 .00000000 1 ,00000000 I njection Area The proposed area of injection, which corresponds to the proposed pool area, is depicted in Attachment 4B. Meltwater Area Injection Order Page 9/32 • e Attachment 4A Meltwater Accumulation Outside Existing GKA Meltwater Area Injection Order Page 10/32 Attachment 413 Proposed Injection Area PAI55.29377 PAI55129377 T BP 39.28223 BP 39.28223 S �1 UCL 4.9506 UCL 4.9506 MOBB 0.3648 MOB 0.3648 Delta CH 3y.N86 C�1y116i086 Ku+paru Rive Unit JC Un t 36 31 ALK4292 ALK4294 ALK4296 ALK4299 ADL375072 ADL375076 ADL375080 ADL375079 A 'A! lU0 PAI55.29377 PAI 55.28377 BP 39.28223 BACHN 6 BP 39.28223 UCL 4.9506 UCL 4.9506 1 6 FORSG MOB 0.3648 MOB 0.3648 CHV 0.1086 CHV 0.1086+ + + + 10-31-05 10 �8 a e 11-30-98 00- No + + + e North o ADL389056 Q 2 ALK4710 ADL373111 ADL3 AP AI 56.4649 BP 41.5351 _ �_ ATOFI Cairn South + +North Interval Netpay Bermuda 10-31-05 10-31-05 Interval Netpay 10-3 PAI 55.507024 PAI 55.507024 + BP 39.433776 + UCL 4.950f- SP 39.43377 +UCL 4.9506� 4- CHV 0.1086 CHV 0.1086 (Subject to DNR Approval) (Subject to DNR Approval) 36 31 36 31 DL389057 ADL389058 ADL389059 ADL3 PAI 58.4649 PAI 58.4646 PAI 58.4649 APC BP 41.5351 BP 41.5351 BP 41.5351 ATOFI 1 1 6 Proposed Meltwater + Iniection Area + + + 10-31-05 10-31-05 10-31-05 10-3 PHILLIPS Alaska, Inc. + + +A Subaldlery o� PHILLIPS PETROLEUM COMPANY O /2 1 2 MILES Proposed Meltwater DL389043 - ADL389046 1 Injection Area Al 58.4649 PAI 100 P 41.5351 -- - 4-24-01 01030104C01 Meltwater Area Injection Order Page 11/32 ) ) Meltwater Area Injection Order Attachment 5 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected The Meltwater Reservoir is the sequence of reservoir sandstones and associated mudstones found in the interval between 4958' and 5368' tvd subsea in the Meltwater North #2A well, and in its lateral equivalents. The Meltwater Reservoir is late Cretaceous in age and stratigraphically within the Seabee Formation. The reservoir is approximately 400' thick and is composed of two intervals. The initial Meltwater Oil Pool includes the entire Meltwater Reservoir, however, the pool definition may change as additional information from development and exploratory activities becomes· available. Both Meltwater and Cairn Reservoir intervals are shown in the wireline log from the Meltwater North #2A well (see Attachment 7). Brief summaries of these intervals are given below in descending order. . The 'T4.1', or Cairn Interval, was encountered between 4958' and 5187' tvd subsea in the Meltwater North #2A well. The boundaries are correlatable markers T 4.1 and T3, respectively. Reservoir quality sands were not encountered at this location, but may be present laterally. . The Bermuda Interval was encountered between 5187' and 5297' tvd subsea in the Meltwater North #2A well. The boundaries are correlatable markers T3 and T2, respectively. Hydrocarbon-bearing sands in this interval were encountered in the Meltwater North #2A and in two offset wells. Two Meltwater Reservoir intervals, the Bermuda Interval and Cairn Interval, are sufficiently understood to be included in development plans. Initial injection will be restricted to these two intervals. An expansion of injection operations (both vertically and areally) may be sought in the future depending on results from upcoming drilling activities. Meltwater Area Injection Order Page 12/32 ') ) Meltwater Area Injection Order Attachment 6 20 AAC 25.402 (c)(6) Description of the Formation The proposed injection zone includes the Cairn Interval and the Bermuda Interval within the Meltwater Oil Pool. This zone lies between 4958' and 5368' tvd subsea in the Meltwater North #2A well (Attachment 7). The Cairn Interval lies between reservoir markers T3 and T 4.1 while the Bermuda Interval lies between reservoir markers T2 and T3. The Meltwater Pool sands are fine- to very fine-grained and have common shale laminations and interbeds. Sands are compositionally heterogeneous: the major components include quartz, heterolithic rock fragments, plagioclase and zeolite. Shale laminations are common. Reservoir sands, which are locally developed within each interval, are lobate to linear in form, and are separated from adjacent reservoirs by mudstones and shales. The top of the Meltwater Reservoir is separated from the Tabasco Sandstone equivalent, the first overlying potential reservoir zone, by a confining layer of approximately 3000' of impermeable shale (Attachment 11 A). The base of the Meltwater Reservoir is separated from the underlying Kuparuk River Formation by approximately 500' of shale. Meltwater Area Injection Order Page 13/32 Meltwater Area Injection Order Attachment 7 20 AAC 25.402 (c )(7) LOQ of Meltwater Tvpe Well MELTWATER NORTH 2A Meltwater Area Injection Order Page 14/32 \) ) Meltwater Area I njection Order Attachment 8 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing Casing The proposed casing programs for a typical Meltwater well resembles the casing programs employed in the Kuparuk River Unit (KRU). Although the standard program incorporates maintaining a tubing annulus with isolation and pressure integrity within 200' of the initial producing interval, exceptions to this design criterion will be required to optimize recovery from potentially productive secondary targets. Standard Casing Program As in KRU wells, conductor casing will be set below 75 feet to provide anchorage and support for the rig diverter assembly. The surface casing size may be 9-5/8 or 7-5/8 inch, depending on casing setting depth and production tubing size. Surface casing will be set below the base of the West Sak interval, effectively casing off the permafrost, Ugnu, and West Sak formations. Meltwater wells utilize a tapered casing string tied back to surface, that serves as the combination production casing / tubing string installation. The casing adjacent from the producing interval is the same size as the tubing is at the surface (monobore). The casing across the production interval is then tied back to surface with a string of 3Y2 or 4112 inch tubing inserted into a seal bore or polished bore receptacle (positioned above the top pay zone perforation.) This provides a tubing annulus with isolation and pressure integrity (see diagrams shown in Attachment 8A). There are three casing programs proposed for the Meltwater development: Case 1) 3Y2 inch Slimhole Monobore completions. This casing program utilizes a 7-5/8 inch (L-80, 29.7 pound) surface casing string with a production string of 5Y2 inch (L-80, 15.5 pound) casing crossed over to 3Y2 inch (L-80, 9.3 pound) casing across the Meltwater interval. These monobore wells will be completed with 3112 inch (L-80, 9.3 pound) production tubing. Case 2) 4Y2 inch Monobore completions. This casing program employs 9-5/8 inch (L-80, 40 pound) surface casing with 7 inch (L-80 or J-55, 26 pound) production casing crossed over to 4Y2 inch (L-80, 12.6 pound) production casing. Case 3) 3Y2 and 4Y2 inch Conventional completions. This casing program employs a string of 9-5/8 inch (L-80, 40.0 pound) casing and an intermediate 7 inch (L- 80 or J-55, 26 pound) intermediate casing string set above the Meltwater formation top. A 3Y2 inch (L-80, 9.3 pound) or 4Y2 inch (L-80, 12.6 pound) liner would then be set across the Meltwater formation and tied back to surface with either 3Y2 inch (L-80, 9.3 pound) or 4Y2 inch (L-80, 12.6 pound) production tubing. Meltwater Area Injection Order Page 15/32 ') ) Each of these three well types may be completed for either production or injection service. The service of the well will be determined after logging operations. Drilling and completion plans for future Meltwater wells may vary with time as experience and knowledge are gained. The proposed method casing testing method for Meltwater injectors is to follow the requirements of 20 AAC 25.412 (c & d). Sufficient notice of pressure tests will be given so that a Commission representative may witness the test. Secondary Targets The Bermuda Interval will be the primary target of initial development efforts. Current plans are to focus initial development efforts on that portion of the interval most likely have good reservoir characteristics. As previously shown on Attachment 7, potentially productive secondary targets in the Cairn Interval may be encountered during these development efforts. Secondary targets in the Cairn Interval are expected to generally be within 400' tvd of the Bermuda Interval. These thin, potentially productive zones contain insufficient reserves to merit separate wells or extensive completion design modifications. Although fracture stimulations are planned for Bermuda Interval producers, fracture modeling indicates these stimulations will only grow approximately 100' upwards. Potentially productive secondary pay zones can therefore only be developed if they can be inexpensively commingled with Bermuda production. Given the initial uncertainty of producer/injector interactions, most producers will be candidates for conversion to injection service. In order to maintain conversion flexibility, there are no casing design differences between production and injection wells. (Casing connections will be designed for gas or liquid service.) The flexibility to convert wells to injection service on an as needed basis is an integral part of the Meltwater development strategy. This complicates secondary target development as these targets can only be pursued if they are not isolated by more than one casing string. Pursing secondary targets may result in exceeding the AOGCC guideline that injectors provide annular isolation within 200' measured depth of the highest perforated interval. Plans are to provide annular isolation within 200' measured depth of the perforated zone, unless secondary targets are encountered with a pay thickness approaching or exceeding 10' tvd. Based on current drilling and facility hook-up plans, the productive nature of these secondary targets can not be fully ascertained during initial drilling operations. If future evaluations indicate that developing secondary targets can not be justified, there is the potential of having either current or future injectors with annular isolation located more than 200' measured depth above the perforated zone. Meltwater Oil Pool Rules are written to help ensure that well service flexibility is not sacrificed by attempting to pursue thin secondary targets. Meltwater Area Injection Order Page 16/32 ') ) Meltwater Area Injection Order Attachment SA 20 AAC 25.402 (c)(8) 3-1/2" Slimhole Monohore Completion FMC Prudhoe Gen V L., i 9-5/8x5V,x3V, I ;:;,:~ ~~;~ J:J'i ~ 2.875" CAMCO~/ DS nipple for Ii Possible K-Valve I ! I 9-7/8" Hole ! ],. 7-SI8" Surface Casing al 2.500' TVD 6*" Hole ~ I~ I - I I I l I I I f I : I .] I Í¡ .Wz"lubing ¡~ I ¡ Baker CMU Sliding ~ ¿ - Sleeve w/2.813" DS' ~ Cameo profile ~ : . CAMCO 2.75" Cameo 3V,' x 1" ........---.... DS nipple side pocket GLM ., j I ...~ St¡¡" Casing S~aL R~ceptack (CSR) Cross~d owr to .Wz"lubing aI5.000· '[V) Meltwater Area Injection Order ~ ~I/Z" Produclion Casing at 5.200' TVI) 13:1SC of p~nnafrosl at 1.250' M) 13as~ of West Silk at I ,800' 'IV [) FMC Prudhoe Gen V L., 9-5/8x7 x 4V, I L, ~ 12'1/' Hole I I I l... 9-SI8" Surf. Csg. at 2.500' TVD 81h" Hole 7" Casing S~aL R~œptadc (CSR) Cross~d ov~r 10 4t¡¡" casing at 5.000' TVD 3-112" or 4-1/2" Monohore Completion ~ ~ -r rOO';bI' K ".. I ~ Jt¡¡" or 4'/Z" ~akerCMU Sliding Sleeve wl3.812" Cameo ~""" side pocket GLM -.¥~ ~ \ CAMeo 3.75" DB nipple (' ! 1 ' . ~t¡¡', or41/z" L-,LI Ja( 5,200' TVI) Page 17/32 ) ) Meltwater Area Injection Order Attachment 9 20 AAC 25.402 (c)(9) Injection Fluid Analysis The vast majority of the MI initially employed at Meltwater will originate from Kuparuk River Unit's CPF-2. During 2001, both MI and water will be employed to provide pressure support and maximize sweep. After completing the MWAG recovery process, plans are to eventually inject lean gas into the Meltwater Oil Pool to maximize recovery of the light hydrocarbon liquids that were injected into the reservoir as part of the miscible injectant stream. The source of the lean gas will likely be Kuparuk River Unit's CPF-2. However, other potential gas sources will also be considered. The initial water injection source will be CPF-2 produced water. Local separation and reinjection of water at Meltwater may be considered in the future. Fresh water collected in well cellars from snowmelt may also be injected for short time periods to minimize road traffic during the caribou calving season. The average MI and lean gas composition produced at the Kuparuk CPF-2 facility during 2000 is presented below. Also shown below is a CPF-2 produced water analysis from February 2000. Maximum MI/lean gas and water injection rates into the Meltwater Oil Pool are estimated at 80 MMSCFPD and 65 MBWPD, respectively. There is no evidence from laboratory core flood experiments or compositional studies that indicate the fluids proffered for long-term injection would pose any appreciable compatibility problems for either the Meltwater Formation or its confining zones. Short periods of fresh water injection are also not expected to cause any appreciable compatibility problems. If injectors do incur damage from fresh water injection, remedial treatments (e.g., acid stimulations, high pressure breakdowns, etc.) can be employed. Meltwater Area Injection Order Page 18/32 ) ) Miscible Injectant & Lean Gas Composition Supplied by the Kuparuk River Unit's CPF-2 Component Lean Gas MI (Mole 0/0) (Mole 0/0) CO2 0.89 0.5 N2 0.27 0.3 C1 81.37 69.6 C2 8.79 6.7 C3 5.10 5.0 i-C4 0.92 2.2 n-C4 1.99 6.3 i-C5 0.30 2.0 n-C5 0.28 2.5 C6 0.07 2.1 C7 0.01 1.8 C8+ 0.00 1.0 CPF-2 Produced Water Analysis Sulfate Sulfide Bicarbonate Aluminum Ammonia Barium Boron Calcium Chloride Chromium FI uoride Iodide Iron Lithium Manganese Magnesium Phosphorus Potassium Silicon Sodium Strontium Concentration (m gll) 159 12 1,920 <0.15 20 35 18 137 13,131 <0.06 <10 12.6 0.74 1.2 <0.003 99 <0.5 60 20 8,800 6.7 Component Meltwater Area Injection Order Page 19/32 ) ) Meltwater Area Injection Order Attachment 10 20 AAC 25.402 (c)(10) Estimated Pressures The maximum MI and water injection pressures available at the plant will be 4,400 psi and 3000 psi, respectively. Due to pressure losses in the distribution system, actual maximum wellhead pressures will vary. Injection wells may also be choked to avoid exceeding injection targets. MI and water wellhead injection pressures are expected to range from 2,600 - 3,600 psi and 1600 - 2600 psi, respectively. Meltwater Area Injection Order Page 20/32 ) ) Meltwater Area Injection Order Attachment 11 20 AAC 25.402 (c )(11 ) Fracture Information Injection into the Meltwater Formation will not breach the reservoir's confining zones. Neither injection nor formation fluids will be able to enter any freshwater strata. Although bottom-hole pressures may exceed the formation parting pressure during enhanced recovery operations (Le., water and MI injection), the Meltwater producing sands are separated by over 2000' of confining shales and mudstones which act as an impermeable barrier (see Attachment 11 A). These confining layers provide a substantially greater barrier than necessary to contain fractures within the Meltwater interval. Fracture modeling using Stimplan (Le., Nolte/Smith's quasi 3-D model) confirms this as predicted fracture heights are entirely contained within the perforated interval. For example, injecting water at a rate of 10,000 BWPD at a surface pressure of 2200 psi would result in upward fracture growth of only 10'. Injecting MI at an injection rate 15 MMSCFPD at a surface pressure of 3500 psi would cause no appreciable height growth. The above-mentioned fracture modeling is based on single, planar, vertical fractures that result from relatively short duration injection. Since these modeling captures neither dentritic fractures nor disaggregation (i.e., destruction of the rock matrix), model predicted fracture growth associated with long term injection is too large. Hydraulically propped fracture stimulations are planned for Meltwater producers. The 1500' of confining shales and mudstones also provide a substantially greater barrier than necessary to contain these fracture stimulations. Fracture modeling using Stimplan suggests that typical fracture stimulations will grow upward approximately 100'. Model runs with worst case assumptions (which cause the most upward growth) suggest the stimulations will not exceed 300' of upward growth. For example, a fracture stimulation with 200,000 pounds of proppant with only 70' of gross interval is forecasted to result in a maximum upward fracture height of approximately 200' (see Attachment 11 B). As previously mentioned, no disposal injection is initially planned in the Meltwater Participating Area. However, the Ivishak sandstone is being permitted for Class II disposal to address potential future needs. Approximately 2000' tvd of confining rock separate this zone from Meltwater Reservoir strata. In addition, there are no potential fresh water strata within several thousand feet of the zone (see Attachment 11 C). If the Ivishak is used for disposal injection in the future, modeling will be conducted at that time using the best available tools to help ensure that the planned disposal volumes pose no risk to either potential freshwater strata or hydrocarbon recoveries. Meltwater Area Injection Order Page 21/32 Attachment 11 A Meltwater North #2A Confining Intervals MELTWATER NORTH #2A GAMNA RAY í RESISTIVITY ~ ::J ~ ~ ~ f.!: !!... 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'" .. .. ++++.++*~++++.+++++~+.++.++~++++.+.+~.++.++.++++~++.+..++.+.+++.+.~+++++.+++++~+++++++~+++++++~++++++++++ .. .. + .. + .. .. +- .. .. .. '" .. .. '" .. .. + .. .. .. .. .. .. .. .. .. + .. .. .. .. .. .. + .. .. .. .. .. .. .. + .. .. .. .. + .. . '" .. .. .. + .. + .. .. .. .. .. .. .. + .. + .. .. .. .. .. .. .. '" .. .. .. .. . · .. .. '" .. -+ .. '" .. .. -+ .. .. .. .. .. .. '" .. .. .. .. -+ *' .. -+ .. .. -+ .. ++...+...+......+..~......+~..+...+.........+..~...+.*.+.+........+++++.+.+++.+...+.+~+++...+~.++.+..+.+ .. .. *' '" -+ .. .. -+ + -+ .. -+ .. .. .. .. .. +- .. -+ .. .. .. .. *' .. .. '" -+ .. .. +- .. .. . .. .. .. .. .. .. .. .. .. + .. .. .. + .. .. . .. .. .. .. -+ -+ .. .. · -+ .. .. '" -+ .. -+ -+ . .. -+ .. .. . -+ . .. .. .. +++++.++~++++++++++~+.++.++~+..++++~+++++++++++~.+.++.++~......+++++..+.+++++~+.+.+.+~.++++++~++...+++.. .. .. -+ .. .. . . .. . . · . '" . .. .. . . + -+ .. +- -+ .. .. .. .. '" . .. .. . .. .. . .. '" -+ .. + .. .. '" -+ . . .. . . -+ .. -+ + -+ . .. .. .. .. . .. .. + .. '" '" .. -+ .. .. .. -+ .. .. .. .. .. .. .. . 0 0 ("'1 0 0 Il) '- ::::¡ ,,; f..¡") 0 E:' lD CL .µ Il) z 0 N 0 20 50 100 Time (min) 200 500 1000 2000 Meltwater Area Injection Order 5.0 10 20 Page 23/32 Attachment 11 C Sinclair Colville #1 Confining Intervals Meltwater Area Injection Order 1m iU'J /ri. i iJit. , ::J \ L- IfO \g. \~ ~ tU .c UJ Jit. tU g) C ~ I Jit. -- :E ::I ..c U'J - D'I fO U'J U) UJ ~ tU .c U) ~ CD C o N .... c CD E CD c :;: c o o - CD C o N c o ;; u CD -- C --- Sinclair Colville #1 Well Page 24/32 Meltwater Area Injection Order Attachment 12 MC 25.402 (c)(12) Formation Fluid No oil-water or gas-water contacts within the Meltwater formation have been encountered. In the Bermuda interval at Tarn, average salinity estimates from immobile connate water were estimated from low invasion cores. Connate water was obtained from core plugs using a miscible (CHCI3 / CH30H) extraction process. Subsequent water volumes were estimated using Karl Fisher analysis and chlorides were measured using ion chromatography. The resultant estimated connate water NaC! concentration was 30 Kppm. Anomalous lab results on Meltwater cores indicate a chloride content in the Bermuda Interval at Meltwater North of 20 Kppm NaCL Due to uncertain lab procedures, Core Labs has little confidence in this value and estimates the actual value (based upon anion calculations) to be in the 35-40 Kppm NaCI range. Further testing on subsequent cored wells at Meltwater is planned. Meltwater Area Injection Order Page 25/32 Meltwater Area Injection Order Attachment 13 20 MC 25.402 (c)(13) AQuifer Exemption The proposed Meltwater pool lies just south of the current Kuparuk River Unit (KRU) exemption area established by the EPA on May 11, 1984 (see Attachment 13A). An extension of the existing KRU Aquifer Exemption Area is being sought. Analysis of all available data indicates there are no potential fresh water sands suitable for human consumption in the proposed Meltwater injection area. No porosity logs were acquired in the surface portion (above approximately 1900' tvd subsea) of the Meltwater North wells. Wells in the general vicinity of the proposed Meltwater injection area (Le., Kalubik #1, Colville River St. #1, Cirque #2 and 2N-349) were analyzed for fresh water acquifers using the SP Technique and the RWapparent Technique. (The RWapparent Technique is referred to as the Resistivity-Prosity Technique, or "RP", in literature.) Both are well known techniques within the industry. Discussion is provided below on the limitations of each method and the associated salinity estimates. Two of the wells (Kalubik #1 and Colville River St. 1) are outside the existing KRU and Alpine Aquifer Exemption Areas. The third well (Cirque is located within the KRU Aquifer Exemption Area. following table is a list of salinity calculations for the sand underneath the permafrost. Calculated fluid resistivities are corrected to 75° F and salinity numbers are NaCI equivalent, or total dissolved solids (TDS). Kalubik #1 Colville River St 1 Cirque 2 2N-349 Rmf = I.l9 Q-m @ 69° Rmf = 2.52 Q-m @ 68° Rmf = 2.28 Q-m @ 85° Rmf = 3.3 Q-m @ 63° Permafrost @ 1510' Permatì'ost @ 1360' Permafrost @ 1170' Permatì'ost @ 131 0' Sand @ 1740'-90' Sand @ 1510'-20' Sand @ 1440'-60' Sand @ 1905'-15' $ = 36 Rt = 12 Qm $ = 36 Rt = 2.1 Qm $ = 34 Rt = 26 Qm $=31 Rt = 10 Qm Rwa = 1.09 Qm Rwa = 0.24 Qm Rwa = 2.1 Qm Rwa = 0.8 Qm (5.3 Kppm) (28 Kppm) (2.5 Kppm) (6.9 Kppm) SP = -35 mv (@ 35°) SP = -40 mv (@ 34°) SP = -20 mv (@ 35°) SP = -20 mv (@ RwSP = 0.38 Qm RwSP = 0.5 Qm RwSP = 1.03 Qm 44°) (15 Kppm) (20 Kppm) (5.4 Kppm) RwSP = 1.19 Qm (4.5 Kppm) Hole badly washed Zone slightly shaly. Hydrates known .SP Hydrates below out. SP probably Salinities quite high. more representati ve Permafrost R wa more representative. though still too low. more representative. Meltwater Area Injection Order Page 26/32 In the Kalubik and Cirque wells, average resistivities drop dramatically below these sands, indicating much saltier waters. In the Colville well, the high salinities begin at the base of permafrost. 2N-349 Base Permafrost picked at 1310' with the section below interpreted to be hydrate bearing. This is supported by a shallow gas sample log obtained in the 2N-305 well (see Attachment 138). Shale resistivities suggest salinities in the 6-10 kppm range. Rwa in the sand at 1910' calculates TDS of 6.9 kppm. This section of the well has wireline logs to 2330' with LWD below that. LWD resistivity decreases systematically below 2400', implying an increase in salinity below that depth. There are no appreciable sands present below in which to verify this salinity, though estimates from the shales would suggest salinities of 20+ kppm TDS. Included as Attachment 13C is a plot of Rwa versus depth for the shallow portion of this well. Kalubik Water salinities below permafrost are estimated to be in the 10-12 Kppm range (TDS), increasing to 25 Kppm below 1950'. An analysis of a water sample from Albian aged sands (5050-5250') in this well tested 24.3 KPPM TDS. Colville River St. 1 Salinities below permafrost are approximately 25 Kppm TDS. Cirque 2 Under permafrost, salinities are 6+ Kppm increasing to 21 Kppm below 2200'. The sand immediately below the permafrost is believed to contain gas hydrates. This causes log based salinity calculation results to be too low. None of the wells exhibit decreased salinity below these depths. Meltwater Area Injection Order Page 27132 Attachment 13A Regional Aquifer Exemption Map AlpineAquifer Exemption Kuukpik Kalubik 1 . S:ar Milne Point Kuparuk River Prudhoe Bay Alpine Pool Sections 2N-349 . Proposed Meltwater Pool 2 Greater Kuparuk Aquifer Exemption N2 Meltwater Area Injection Order Page 28/32 Attachment 138 Tarn 2N...305 Shallow Cuttings Samples T RN 2N-305 SHALLOW CUTTINGS GAS SAMP S C02 neoG5 Meltwater Area Injection Order Gas Hydrates Page 29/32 Attachment 13C Rwa vs.. Depth for 2N....349 W ¡ EP C ssp I (OHMM) Meltwater Area Injection Order Page 30/32 . . Meltwater Area Injection Order Attachment 14 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery The Meltwater Sand was tested in the Meltwater #1 exploration well. Fluids recovered from the test indicated the interval contains 36° API gravity crude with a solution GOR of approximately 620 SCF/B. There is no evidence that this zone is in contact with either an aquifer or gas cap to provide pressure support. Simulation results indicate that an MWAG process with a cumulative 20% hydrocarbon pore volume slug of MI would provide an overall recovery factor of approximately 38% OOIP. This recovery factor is approximately 9% OOIP higher than that obtained from waterflood and more than 20% OOIP higher than that obtained from primary depletion. Meltwater Area Injection Order Page 31/32 . . Meltwater Area Injection Order Attachment 15 20 AAC 25.402 (c)(15) Mechanical Condition of Existing Penetrations There are no active wells within a one-quarter mile radius of the Meltwater Oil Pool. However, two exploratory wells and a sidetrack were drilled to evaluate the area. These penetrations have been plugged and abandoned as per AOGCC regulations (20 MC 25.112). All casing strings were cut three feet below the original ground level with well abandonment markers installed as per 20 MC 25.120. The well cellars were removed and the remaining holes back filled to ground level with gravel. Meltwater Area Injection Order Page 32/32 I I I I eti eo I Reservoi IIi 9 a S a S a Stra Steve ootha La 0 o pletio s eil es ya Stra Stra "* A Written Brief Has Also Been led 2 May 7, 2001 3 May 7, 2001 4 III Drilled Wells IIITested MWN#1 1 Sidetrack 1 Q2000 Meltwater North Well Test Rates & Pressures 5000 4500 4000 "C 3500 Q. .Q 3000 ~ 2500 ~ 2000 Õ 1500 1000 500 o o 20 40 60 80 Flowing Time, Ius May 7, 2001 1000 .¡¡¡ Q. Ii' l- LL .. 500 ~ ö¡::: o III ci o C) o 100 reate I et Ie In .. .. " I I " ) ross Reserves .... 5 May 7,2001 -Construction egan J nuary 2001 -All n dra Construction Now Complete - urrently rilli g irst evelopment ell - n-Pad Constructio In Progress - nticipate irst Production By ct. 1, 2001 6 May 7, 2001 - I ieatio .. .. IS SSI S - la S I ress - Expand Kuparuk River U it - Form Meltwater rticipating Area - - 7 pli 0 S ill I el e peratio s, a e iI i alia S fo ploratio ay 00 Develop e May 7, 2001 8 Attachment NO.5 Proposed Kuparuk River Unit Expansion and Meltwater Participating Area 01030104AOO May 7, 2001 hillips Alaska, Inc. B Exploration (Alaska) I Unocal obil ( eritage) Chevron Total eltwater Lease old Parti pation Interests 55.380345% 39.343780% .950600% 0.216676% 0.108600% 1 00.000000% Agreed Among Owners Lease Assignments Not Yet Complete 9 May 7, 2001 " aste a ote se 0 " I " ate Reeove " pa est Sak, , Slope ools 10 May 7, 2001 el ate 11 5500 7300 8' 187' 9 , May 7, 2001 001 Alaska, Inc. A SubSldla.ry of PHILLIPS PETROLËUM COMPANY Proposed Meltwater Pool Area 01030104C01 12 May 7,2001 13 May 7, 2001 14 May 7, 2001 May 7, 2001 May 7, 2001 Tam Net Sand Map May 7, 2001 el a 4900.00 5000.00 5100.00 (.i ~ c:o::t (.i 5200.00 00 5300.00 5400.00 2200 Subs ea Depth .vs. Fonnation res sure Tam 3APres s ures Tam 3AOil Gradient Tam 4 Pres s ures Tam 1 Pres sure - Tam 4 Gradient(?) " 2L-315 Pres sure 29 2L-315 Oil Gradient Arete Gas Gradient MWN 1 MWN 1 Gradient MWN2A MWN 2AGradient 2L rp Gas cap at 5 1 4 1 f S s tvd 2250 2300 2350 2400 50 2500 Formation s sure May 7, 2001 19 Tam Tam 4 . MWN MWN2A MWS Sandstones are qnartz Poor (20%) bulk QM + QP + chert Largely comprised of SRF, MRF, and VRF rock fragments SRF's and MRF's are argillaceous (structural clay) VRF's are largely pyroclastic glass shards altered to analcite Analcite cement locally fills pores around the remnant shards l May 7, 2001 4 " MWN2A SRF's and MRF's are argillaceous (structural clay) VRF's are largely pyroclastic glass shards altered to analcite Analcite cement locally fills pores around remnant shards 20 May 7, 2001 1000.000 1.000 100.000 10.000 0.100 --- Tarn 0 Tam4 MWN MWN2A MWS 0.001 0 5 10 15 20 25 30 Porosity (%) 21 May f, LVVl I i - M It water North Type Log o Between 4958' (T 4.1) and 5297' (T2) sstvd - Geographic imits @ò Sections 1-36 of T8N, Ie - iel a I a e - Kuparuk River ield - Meltwater il Ie "" 22 May 7,2001 I la ilia pose I les 23 May 7, 2001 eltwater Sim (Injection ube Simulation Results id is Kuparuk I) 100 > 0.. N 95 - - @9: ~O (DO 90 >~ O~ u (D r.t: 85 MMP= psia 80 2050 2100 2150 2200 2300 2350 2400 2450 Slim Tube Operating Pressure (psia) 24 May 7, 2001 50.00 45.00 40.00 35.00 ~ 30.00 ~ "w 00 o o 20.00 0.. Porosity as a of Pe rmeabmty (Tarn Analog for Confined Flow Turbidite Facies) 1 00 1 00 5.00 0.00 o . . y = 18. 714xo.067 50 100 Permeability (md) 150 200 25 May 7, 2001 Water Saturation as a nction of Porosity (Tarn Analog for Confined Flow Turbidite Facies) 100.00 90.00 . --- 80.00 - ~ 70.00 0 - 60.00 ., :::s 50.00 --.---. ... . co . (I) 40.00 II.. Q) 30.00 ... ~ 20.00 10.00 y = (4290)(x)[(-0.0167)(X)-1 0.00 0.00 5.00 10.00 1 00 20.00 25.00 30.00 35.00 Porosity (%) 26 May 7,2001 Stochastic Permeability Distribution (Confined Flow Turbidite Facies) 27 . May 7, 2001 Pattern ode I Results for Confined low urbidite Facies Recovery A unction Of HCPVI 60 55 50 45 40 35 ~ 0 - 30 ~ CD > 25· 0 U ~ 20 15 10 5 0 0 28 - ... ---.... .. .11II .. . Á NNVAG w/Water Chase (20% HCPVI MI) . Waterflood MI Flood w/Lean Gas Chase (20% HCPVI MI) Lean Gas Flood 0.2 0.4 0.6 0.8 1 1.2 1.4 Total CPVI May 7, 2001 -- iI!i I I iI!i I I - Stochastic Models ully Compositional ithofacies Dependent omogeneous odels lack Oil Pattern Configuration pe dent - Res Its MWAG Recovery Provides Incremental 90/0 001 29 May 7, 2001 Iii I iI!i I Recovery Benefits (-9% OOIP) - KRU Impact Gas Storag Benefit No Appreciable Adverse Recovery Impact I Availability Infrastructure Miscibility - Infrastructure "Opportuni down 30 May 7, 2001 10 Iii 2001 D lUng Continuous Drilling of -1 Wells Phased Drilling on a Regional Basis Test Cairn Accumulation rly in rogram Develop "Sweet Spots" & Test riphery 2002 D lUng D II -9 Wells Probable rilling reak du ng loration Season 31 May 7, 2001 I III 10 MWAG Maintain Reservoir ressure to nsure Tertiary Recovery nefits lized Minim Injectors until Well Interaction better Understood Pursue A ressive Initial MI Injection Schedule for Overall G Rate Be efit Optimize Cumulative MI Slug S by Pattern based on Performance Gas Recover NGLs 32 May 7, 2001 Itwater roduction recast 30000 0 25000 OJ 20000 Gross Production - s::: less Backout 0 ...... 15000 ......, (J :::s "'C 10000 0 !I... Q.. 5000 ..... ...... 0 0 2000 2005 0 2015 2020 2025 Year 33 May 7, 2001 III III I I io ( i I - Cumulative Slug S I nrichment II Spacing o ntal/High Angle - Pattern Co guratio - Well Location Refinement 34 IIiI I lis e ase ) May 7, 2001 ell 155 es Artificial Natural low M I/Gas Lift et u p ift Possibl ressu Reduction Seco dary rgets Thin, Marginal Cairn luate ability Annular Isolation 35 May 7, 2001 Shallow Zon Well Completion Issues 36 May 7,2001 11II rvlew II Tests - Gas Sam les ressure Measure nts - Surveillance logs 37 May 7, 2001 I P ill 001 - Spaci g Units (Rule 3) - Injection Well Completion (Rule 5) - Reservoir ressu onitori g (Rule 8) - GO Exemption (Rule 9) - Timi g of Injection Start-Up (Rule 10) - Reservoir Su ilia ce Reporting (Rule 11) 38 I s May 7, 2001 Spacing nits - Minimum of 10 Acres - No Closer than 300' from Ownership Change 39 May 7, 2001 Inj ctio ell 0 pi io s - Injectors with ~ 200' between Top Perforated Interval & Annular Isolation ptions to 200' Rul whe ursuing Seco dary Targets withi the Meltwater Pool 40 May 7, 2001 iI!i eservol - In I Press 5 III I urvey on Eac Well inimum Annual Number of ressure Surveys Equal to the Number of Produci g or Injecting Gove mental Sections withi e Pool - Reservoir ressure m of 5400' Subsea - Pressure Surveys Stabilized Static Measurements, Falloffs, Build ps, Multi-Rate Tests, Drill Stem Tests or Open Hole Tests - Res Its Reported Quarterly - Res Its from "Special Tests" Reported Quarterly 41 May 7, 2001 xe pt from roduci g GOR mits 42 May 7, 2001 Initiate 43 11II 10 - in 6 onths of Prod o May 7, 2001 I ill ill I - Reservoir Management Update - Produced & I luids by Interval - Reservoir ressure alysis - Multi nterval roduction & Injection Logs - Well location & II Test luatio uture Development lans 44 May 7,2001 45 Typical 3-1/2" Monobore Completion FMC Prudhoe Gen V 9u5lS x 5% x 3% 2.875" CAMCO OS nipple for Possible K-Valve 7-5/8" Surface Casing at 2,500' TVD Cameo 3%" x 1" side pocket GLM 6%" Hole Baker CMU Sliding Sleeve w/2.813" OS Cameo profile CAMCO 2.75" OS nipple 5Y," Casing Seal Receptacle (CSR) Crossed over to 3Y," tubing at 5,000' TVD 3Y," Production Casing at 5,200' TVD Base of permarrost at 1,250' MD Base of West Sak at 1,800' TVD Typical 4-112" Monobore Completion FMC Prudhoe Gen V 9-5/8" 7 " 4% 12'/," Hole 9-5/8" Surf. Csg. at 2,500' TVD 8%" Hole 7" Casing Seal Receptacle (CSR) Crossed over to 4Y," casing at 5,000' TVD May 7, 2001 asing nd C me ing ces - Conductor Set at Least 75' Below Ground Level - Surface Casing at Least 500' low rmafrost for Annular u ping 46 May 7,2001 TREE CAP SWAB VALVE 4Y1s"-SØøø# API TEE 4Y1a"x3Ys" SØØØ¡¡ API SURFACE SAFETY v. 4- Y1s" - Søøø# API MASTER SURF ACE v" 4 Y16" Søøø# API TUSING HD ADAPTER n"-søøø# API CASING HEAD 11"-5ØØØ# API LANDING RING CONDUCTOR (16"Ø) TREE ASSEMBLY 47 May 7, 2001 uto atic Sh ui e t - Fail Safe Automatic u ce Safety Valves on All Wells - S rface Safety Valves Tested ry 6-Months 48 May 7, 2001 ydroge 5 de .. la . 0 I ge cy MC .065 ata at e .. ents . I AAC 25.0 1 (a), (b )(1), and ( )(2) 49 May 7, 2001 - ravel oad a ad (1 iles )* ges ctio I .. I e " - " ate I ectio iscible I ectant -8" .. Ene - ve e owe i e -1 liS 50 May 7, 2001 51 May 7, 2001 6 Miles to DS 2M @ tk~ ~O 1J $ 1 «) Miles DS 2M to DS 2N (0 ..- "Tarn OS's" $) Miles DS 2N to DS 2P 52 ;: "Ñ . - * $ . l2f)T® . ~øø @) "Meltwater" "4-Corners" Intersection New Tarn Pipelines" New Meltwater Pipelines May 7, 2001 -Tru k a d Late I Well Manifolding - Production - Test - Water Injection - Miscible Injectant -20' Wellhead Spacing -Conventional Well Test Separator -Remote Well Test Actuatio -Remote Control II Cokes - D Skid - lectrical/Control Room 53 May 7,2001 54 ".~'<II~"-'''I> ----- "- -------~ -~. ------------.--- ------."-- --. ----.------.... -."- .-.-- . .. '¥0" ISSlEO FaA t:OÑS1AutUON...::':_ ",19)S1" ! .1 ~ í ~ :r ~ ~ ~ :r ~ : ~ ~ , "ff";'-" ~ '- '- , ~ ~ " ~ ~ , j :~ t<~·-·_·-·+·~·-'-·~·~·-'-·~~·-;-·~·~·-~-·~·~~-·~·~·-~_.~.~.~_ .~"~.-1-"L·~·-t-·---------.-----.-- :: .<-'!........."'---.---. . . . . . . . - . . - . . " - - . - {. ::"'if' ~~." - J..,. J d'.... - 'J'. ~~_.-..-----4- ~- ~ t- t-... ~ ¡., ¡.... ~t-""I- ... I-f-.... 1-1-1-1-1- ¡., 1-1-1-1- t-I-~ I- ¡.... +-I-+- t-Jrf- t- f-I-t- \1-1-1-1-"1- .... ~_~_.. '-';~7i-r .. . - /. ,.~ . . - . - . . . . . .~ r·I._1~ ~L=." tJ"..I~...N~.-~ ¡ 2Pl7 /I ,- ~ ~ ....- J ueo-r. ¡-J ,2P83 I-=-=.: 1..11IoI_ . -+-S--i:.-t+---.~1I"', 1 '.n ta. 1w-r·' ~ r-1 j t-. "' 1r'-~ .':.... ¡ ~ I I . w-_ ...L. I '-:"'--1 ----:::t1--+--~---+-- ¡~r7J _J~ --~ ¥ - ~ !.. ,p g; o.c -... A1051 ? Alaska Anvil Inc. __......atll!ll _""....,~aM _..,..'n......~..1s a ji1~I!.IbD~~ ~_læ. Dœ. ~A~rtI~l"'fimIIOI..eU~ - - AR(k 2P 1,IOQ1IL£:2P"IÐ IIS2P Sl1E fI.AH -øëìê May 7, 2001 . , . . 'i'" .1 .1 J. .L _ _.-c~:.-~ooa::OOCI _ lr ;.!EM l. r AlllJrl ~MU'SS -. >I~" J. OJ88£RN """ _ ....",rn,_ _.....001> S. tARN ;;..",. _.. PDD-02PY-10p'1 ;;:--l lit UNlT:Ol ,......_~..-c - ~~----. .----(~..:r_--.- ----4~..,.r--~--- , . ._....~~._._. ,I, JF -t--t~~ . ..!.1J0"-- /-.c!L~'''---../'/ Meltwater Pool Rules Hearing S2P ~ad ty.ayout - - - - - - - ! . ~ J : ;1 ~I !I !I !I ;1 !I 'I ~ . . . ~ j~ Meltwater Pool Rules Hearing · Conventional Vessel . · Gas/Liquid Separation Only · Metering Devices - Total Liquid - Micro Motion Mass Flow Meter - Liquid Water Cut - Phase Dynamics Meter - Gas - Vortex Shedding Meters . 55 May 7,2001 . . Meltwater Pool Rules Hearing ~ ~ Common Production Facilities and Suñace Commingling - Surface Commingling of Meltwater and Other Greater Kuparuk Area Production - Floating Allocation Allocation Factor Scheme for KPA and GKA Satellites (Pending Agency Approval) - Two Well Tests per Month - Monthly Reports of Allocation and Test Data 56 May 7, 2001 Meltwater Pool Rules Hearing ~ (, ¡¡ dl l :L~ ã (11 '~' ~ ,,? .:~..' ;1 a Cii'i>,,^f:i ':h':· ~'(\;,~J ;¡',::r 4¡i;o". ?'f~,,~J\i¡, ''''/"';.'' ,;1'I!'(1!\' "lit! :;~,j"-j',': ':-;:.H,~;,.. ",;, ·:It YI".f)! ~~'I' ~~ r;qj~", a " " "j, "~I ',1 >," ,", ", "'. '-'.;;:) ~,:';~;4 \'¥ ~,! !'¡: I\i;';~,:r. ~"¡'i,w $:¡;@' KPA + All GKA Satellites Have Variable Alloc. Factors . If Overall Alloc. Factor is Less than 1.02 · KPA and All Satellites Have Same Alloc. Factor If Overall Alloc. Factor is 1.02 or Greater · Alloc. Factor for All Satellites Set to 1.02 · All Residual Production is Allocated to KPA . *Change to Previous Allocation Factor of 1.0 for GKA Satellites 57 May 7, 2001 Meltwater Pool Rules Hearing - Rule 12 - Production Anomalies (Proration Events) . - Attempt to Cut All Pools by Equal Percentage - May Vary to Avoid Equipment Damage and/or Increased Operating Costs Rule 13 - Administrative Action - Commission May Administratively Amend Pool Rules . 58 May 7, 2001 Meltwater Pool Rules Hearing I - - - Rule 1 Field and Poo Name Rule 2 Pool Definition Rule 3 Spacing Units Rule 4 Casing and Cementing Practices Rule 5 Injection Well Completion Rule 6 Automatic Shut-In Equipment Rule 7 Common Production Facilities and Surface Commingling RuleS Reservoir Pressure Monitoring Rule 9 GOR Exemption Rule 10 Pressure Maintenance Project Rule 11 Reservoir Surveillance Report (Annual) Rule 12 Production Anomalies Rule 13 Administrative Action 59 May 7, 2001 . . . . 8 œ. $- r\;;, Meltwater Area Injection Order Hearing May 7, 2001 . . Meltwater Area Injection Order Hearing Application Requirem nts 20 AAC 25.402{c) 15 Requirements 4 Covered During Pool Hearings 11 Covered with Additional Testimony 2 May 7, 2001 . . Meltwater Area Injection Order Hearing Pool Rule Hearing Reference Area Injection Order Proposed Operation Depth & Name of Affected Pool Casing & Testing Methods for Injectors Incremental Increase in Ultimate Recovery 3 May 7, 2001 Meltwater Area Injection Order Hearing Discussi n pies Area Injection Order - Existing Penetrations within One-Quarter Mile . - Operators & Surface Owners within One-Quarter Mile - Affidavit of Notification - Type Well Log (Injection Wells) - Formation Proffered for Injection & Confining Zones - Water Analysis - Applicable Freshwater Exemption . - Injection Fluid Data - Estimated Pressures - Evidence of Injection Confinement 4 - Mechanical Condition of Wells Penetrating Injection Zone May 7, 2001 PHilliPS Alaska, Inc. A Subsidie¡y of PHilLIPS PETROLEUM COMPANY Proposed Meltwater Injection Area V IV.:IVIV,+I.JVI 5 May 7, 2001 . . Meltwater Area Injection Order Hearing Notificati n 20 AAC 25.402 (c)(2) Qperators and Suñace Owners within One Quarter Mile of Injection Qperations Operator: Phillips Alaska, Inc. Attention: Dan Kruse ATO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owner: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 6 May 7, 2001 50 7 4958'sstvd 5187' sstvd 5297' sstV( May 7,2001 I RESISTIVITY LWD.GRC 2 GAÞ! c ~G; øæ ø 8 ..J ~ W ... æ May 7, 2001 I II GAM M A RA Y 9 /~ \! ill.) -¡ J:: (J) en (J) - ill.) I: o N - ill.) I: o N Well Log 4/98 May 7, 2001 Meltwater Area Injection Order Hearing Formation Water Analyses -No Water zones encountered at Meltwater by exploration . wells -Connate water obtained from core plugs using miscible extraction process -Chlorides measured by Ion Chromatography . - Chloride content 20-40 Kppm TDS -Range due to chlorides diffused by drilling mud filtrates -Currently gathering a core with tracer data to pin down water composition 10 May 7, 2001 AlpineAquifer Exemption Alpine Pool Sections 11 N2 Proposed Meltwater Pool May 7, 2001 , , Meltwater Area Injection Order Hearing Iculated Sh lIow S n alinity Kalubik #1 Rmf= 1.19 Q-m 69° Permafrost 1510' Sand @ 1740'-90' <I> = 36 Rt = 12 Qm Rwa = 1.09 Qm (5.3 Kppm) SP = -35 mv (@ 35°) RwSP = 0.38 Qm (15 Kppm) Hole badly washed out. SP probably more representative. 12 Colville River St 1 Rmf = 2.52 Q-m 68° Permafrost 1360' Sand @ 1510'-20' <I> = 36 Rt = 2.1 Qm Rwa = 0.24 Qm (28 Kppm) SP = -40 mv (@ 34°) RwSP = 0.5 Qm (20 Kp m) Zone slightly shaly. Salinities quite high. Cirque 2 Rmf = 2.28 Q-m 85° Permafrost 1170' Sand @ 1440'-60' <I> = 34 Rt = 26 Qm Rwa = 2.1 Qm (2.5 Kppm) SP = -20 mv (@ 35°) RwSP = 1.03 Qm (5.4 Kppm) Hydrates known .SP more representative though still too low. 2N-349 Rmf= 3.3 Q-m 63° Permafrost @ 1310' Sand @ 1905'-15' <I> = 31 Rt = 10 Qm Rwa = 0.8 Qm (6.9 Kppm) SP = -20 mv (@ 44°) RwSP = 1.19 Qm (4.5 K pm) Hydrates below Permafrost R wa more representative. May 7, 2001 :2 13 H ) o May 7, 2001 Cchn: V5 B-1 C02 C1 o 500 1000 :É £ 1500 " '" o 2000 2500 3000 88888 °88 ;2~¡¡¡Rð5 §8 ~ uUL uUL 14 G2 C3 iG4 oC5 iC5!nC5 IC5 C6 C1!C2+C3 IG4/nG4 oC4 nOOCS o § § O.,..(\j(lt)VOd~"! ~ <-I May 7,2001 Gas Hydrates 1800 1600 1400 1200 1 U) 800 <t C) 600 400 15 ..305 D and GAS SHOWS 110.0 o o 100.0 500 1000 1500 2000 2500 3000 3500 ft) ~ C') CD "C - Q. :::;) :ä May 7, 2001 , , Meltwater Area Injection Order Hearing Aquife Exemption Summary -No apparent fresh water zones in Meltwater area suitable for human consumption -Applying for an Aquifer Exemption for the Meltwater Pool 16 May 7,2001 , , Meltwater Area Injection Order Hearing Injection Fluid Data Injection Water Composition Component Concentration Í!!!9ill 159 12 1,920 <0.15 20 35 18 137 13,131 <0.06 <10 12.6 0.74 1.2 <0.003 99 <0.5 60 20 8,800 6.7 May 7, 2001 17 Su Ifate Sulfide Bicarbonate Aluminum Ammonia Barium Boron Calcium Chloride Chromium Fluoride Iodide Iron Lithium Manganese Magnesium Phosphorus Potassium Silicon Sodium Strontium Meltwater Area Injection Order Hearing - Inj ction luid D Lean Gas and MI Compositions Component Lean Gas MI , .(Mole % \ Mole %\ CO2 0.89 0.5 N2 0.27 0.3 C1 81.37 69.6 C2 8.79 6.7 C3 5.10 5.0 i-C4 0.92 2.2 n-C4 1.99 6.3 , i-C5 0.30 2.0 n-C5 0.28 2.5 C6 0.07 2.1 C7 0.01 1.8 C8+ 0.00 1.0 18 May 7, 2001 Meltwater Area Injection Order Hearing Pre SlJre, Inj Confinement ondition of II - Estimated Pressures , Water Injection: 1600 - 2600 psi MI/Gas Injection: 2600 - 3600 psi - Evidence of Injection Confinement (wlWorst Case Modeling) Mllnjection: No Appreciable Growth Water Injection: Upward Growth of -10' , Propped Fracture Height: Upward Growth of -200' - Mechanical Condition of Wells Penetrating Injection Zone P&A (20 AAC 25.112) Casing Strings Cut 3' Below Ground (20 AAC 25.120) 19 May?,2001 #4 S l ~(J t heari n v -...- ~ ( : J Æ,~Ç_ ( I "'- r . ~(9 n Hc~e ~ e~si &,) ~) #3 .:;t:J~1 1ft: ;j-;¿;¿- 1 ; ;¿:t}tlt'M ;t'NILLIt',:; üM t'KUJtr ï~ '..... .. ""K 1)· J CJreater .. L1]Ja:rUl( Área. _"'~._ (. ... kA .. . ...) "We Talk Safety First"" . to.. . ._n'_ prt¿¡~e.t~ð?~£t? nee PhiUip'ii AIWika, I'nç, ß"¡~,':\k;:j '!\~1:role\.!l·n ('ontr':l\:I.~jr~;. lnt'. Almìku ,.t\nvi! 11\;;, tlU( Z(Ö(~qZ;~ 1/ Z FAX t-'\~1'~A1'~L.... f'oot.. fQ;,~/~1 0 Fï L:L .. t~·ì ~ i .: EI V'Cl, 11 ' j I Greater Kuparuk Area Projects MAR 2 2 2001 Phillips Alaska, Inc. . ... Con ,,_~ P.O. Box 100360 AIIIk8()1&Ga8 S.\NIJI....uI. Andøage Anchorage, AK 99510..0360 Facsimile · (90!> 263-4.035 Confirmation · Date: .~ . -.'., ,- : .. -,- ".11.-'" ...._\... ~. .. J:c"'ax: . ." ··..·..1..· .."... ":;,.NT-· _.- .. ... - ...- .-_. . -. .To: .~.""fll Company: AOnC(.- ~om: ~~~~ ~~-~ Phone: Panes (includine cover) ~+ \ C.c: ,..-. Sub.iect; I I o Urgent D For Review D Please R~ply D Please copy & Distribute Locally COMMENTS: 11t, liI/I.t ~ ~tA 14y,!"..¡f. . '.lH. ~ . _ t.,,, t,,-~ . ..J..r"~ 4)1aØW'i_~ hIVItM..",. h'l <"/~· /"'y' ,It, ~fJ,I;O^'¡'A - - -.. ~._. "'R _~.. .... ., -I-~N.) .J-'7P, S~IIW~. '-.'~.~._. . ..... -- --- - . - 'í?1I1J1\_,-·_u . , ' RECEIV'ED MAR 2 2 2001 Alaska Oi' & Gas r.JVI~ \l\fttmHtðß Anch -""'''W' JrJ . orage . 1'1. No.. lease No. Exp. Date Legol D"crlp.1on [eœe A/:;œ$ . 142 roaN, R07E. UM Sec. 4: AJt Sec. 5: .AJl: Sec. .AJJ1313H2 . I1lðOiYa 6: Aft Sec. ï: Aft Sec. ',8: All; See. 9: All: Sec. 16: All; Sec. 17: An; Sec. '8: AIL 1.4.3 .4CL373111 roaN, R07E, :JM: Sec. 1 : At Sec. 2: Aft Sec. n i3Cm 3: All; Sec. 1:J: All: Sec. . ,11: All; Sec. 12: All; Sec. 13: All; Sec. 14: All; Sec. 15: All. TeD '. ,ACl~aroæ maN, R07E. UM: Sec. t 9: All; Sec. 2G: AIt : Sec. 21: AU: Sec. 28: . C,/:! ','05 ; All; Sec. 29: All: Sec. 30: All; Sec. 31: All; Sec. 32: Aft, Sec. 33: ,All. . TBD : AJ:\.'IftOOfn T08N, R07E. UM; Sec. 22: Ail; Sec. 23: AU: Sec. 24: All; Sec. 25: 10131.'t)5 AJI; Sec. 26: Alt Sec. 27: All: Sec. 34: All; Sec. 35: Aft Sec. 36: All. T* ._~, . - - lease Jnfonnation for Meltwater Pool Rules and Areà Injedlon Order 5.[)!33 5.760 ~607 5.760 11..343 LMIof RoyafIV 12 rot. , 2.5O'I. 12.5Iß; 12.~ Alaskø Net ProftSftcr. C.O'" 0,(1% 0.0% 0.0$ 1.11'1I1 : r~ FA? Yes 'r'ê$ 1\-0 ExporsJcn _ PQrtbl . Exp::lI"ISion No ¡\Qleed WQ~ InlefèStl Philips AJaska BPX UNOCAL Total MOBil CHEVRON ." "2 1 .3 5!;.29Jl43 39.252256% 4.';00600% O.364ðO:»i.; O.l0ò60Q"J> .. ! 100.('(XX)(P;!l. f'artia .. --.. ::-: - - -.!:-- :::' . _ :~;:;·i;: - . :"!:=:::f-:- _':'_':, "." 0'" ~~ ~-. - . < : ~:: ::= - ~.~ ~-: -: : - .: .~- ?:;.: .. . f',,~j;~a~r:~f'fî!; >v,~·¡;,·~~'-Q~':.:~I~ " . . 100.oonm ' . . 1 ~ ..c ª : .:9 \!?;;~r:·1~fE~~r.~~~;;~~~w;,:;~:,~~: 55.293744% 3'?.:282256% 4.9.::¡œoc,% G.Jé400:ni a.106lf.C'ì6 IOO.1XKX'm(, ~ :! .§ '< ¡ ~';~¡r;';~~"f{~;')~~~i';~R!t'6~,]J;Pf! 5S.-S07C24% a9 ..43311tJ% 0..1 (J86OC)%. K'G.IX~ 4.950600% o.o:o:oo~ '0 ~ IÐ a ~ D.DCJ.'IX.Q'% O. 108iíJ{J'J., 100.'.Xr~ æ.ro7024~ ']9A~3776~ 4.~ fïCi¡'~;~;Jwi:r~~f¡r,t1.~~¡\~;~fJ!:~r!:t;:::~ ·I~::'~ . . - . ;:. ;,,', '. \! :~: _.'.: . ~.. . r ... ..... ..! : ::. . . ....: - '.0: . . (/) I~ -3 ~ Ltð I ~ ~ I I-' ~ ~ $@ æ ~ F ""'C V; o ~ '"t 3 . .:... Li ~ c ......¡ ('...: ......¡ a -.J CJ1 ..¡;o l'-: ~ l'-: " [\.; #2 ~) NOTICE· TO PUBLISHER I) .. INV. MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDE~.. CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATrACHED COPY OF ADVERTISEMENT MUST BE SUBMITrED WITH INVOICE .,' ~ :.5J:E;;ftQ11øM~F.œJ,N)(O~;AQQRß~$t~;":":: ~~~~{ ~,·:~·('~~~1tr"~~tJjiJ~:~~$?ß.t:r:~¡~$~~~þ~¡j'~'?~~t,:"i'f.~'~ F AOGCC R 333 W 7th Ave, Ste100 o Anchorage,AK 99501 STATE OF ALASKA ADVERTISING ORDER M ~ Anchorage Daily News POBox 149001 Anchorage, AK 99514 Type of Advertisement ~ Legal REF TYPE 1 VEN 2 ARD 3 4 FIN AMOUNT 1 2 3 NUMBER 02910 Sy 01 4 RE~I°è!;PO}vfÁ 02-902 (Rev. 3/94) ADVERT1SING ORDER NO. AO-02114014 AGENCY CONTACT DATE OF A.O. Jody Colombie PHONE April 4, 2001 PCN (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: April 5, 2001 THE MATERIAL BETWEEN THE DOUBLE LINES. MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: D Display D Classified DOther (Specify)~ SEE ATTACHED PUBLIC HEARING NOTICE AOGCC, 333 W. 7th Ave., Suite 100 ~chora~e,AJ(99501 AMOUNT DATE CC PGM LC TOTAL OF PAGE 1 OF ALL PAGES$ . 2 PAGES COMMENTS ACCT FY NMR 02140100 DIST un 73540 DIYISION APPROVAL: .lJrrJ.L i~ <DuM:. T Publisher/Original Copies: Department Fiscal, Department, Receiving AO.FRM &,) () AMENDED Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Meltwater Oil Pool, KuparukRiver Field - Pool Rules and Area Injection Order PHILLIPS Alaska, Inc. (PAl) by letter dated March 12, 2001, has applied for an area injection order and pool rules under 20 AAC 25.460 and 20 AAC 25.520, respectively, for development of the Meltwater Oil Pool, Kuparuk River Field, on the North Slope of Alaska. The Commission has set a public hearing on the Applications for the Area Injection Order and Pool Rules on May 7, 2001 at 9:00 am at the Alaska Oil and Gas Conservation Commission, 333 West ihA venue, Suite 100, Anchorage, Alaska 99501. In addition, a person may submit a written protest or comments on· the applications prior to May 7,2001 at 9:00 am If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before May 1, 2001. ~~~ Camillé Oechsli Taylor Commissioner Published April 5,2001 ADN AO# 02114014 ~) ~ ) Anchorage Daily News Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 TOTAL 822766 04/05/2001 02114014 STOF0330 $76.11 $0.00 $0.00 $76.11 $0.00 $0.00 $0.00 $76.11 $0.00 $0.00 $76.11 STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and dUrIng all saia time was printed in an office maintained at the aforesaid :place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of saId period. That the full amount of the fee charged for the fore~oing publication is not in excess of the rate charged private indIviduals. '.,..A.·.·.;. M~~D~[) ,," ~otic:e()f.·..i. P.Ub.I.i.~·..I'I.e~ri.n,,! STATE .OF AL.ASKA Alaska Oil and Gas " Conservation ;cómm ¡~~i~~" 1;·~~~~tlk~~!ì~:$Wi~.~g:I:\ . re~~:o~'t::~Je~nd Area In-I I I ; PHILLIPS 'Alasko. Inc. ' '<PAl) bY letter dated I I March 12,2001, has. ap- I 'plied for an area ¡niec- 'tion order and pool rules! ~~dÃ:~~0~~5~l,5'r~~paenc~ ¡ : tively, for development of ! I the Meltwoter Oil Pool, : ~~~a~u~ ~i~e~ r~~~' ~~ l Aløs~p; ··.",·,·i·...·,.'··...·..... '.< .......'.'.......... .......l f h~'C.)n'1rni..s;¿ rit;CI ~ \i~ti a D,;blic hE'ar,ng on IhE' 'I Þ"DI,COI,on.. 'c.r In.;> Ar..a mlE'c'ic.n OrClE'r ana POOl , FC\.I..':I (In Ma~ 7 200 I al ! ~.OO am a' Int' Ala':lka 0;, I I Signed ~ ~ Subscribed and sworn to me before this date: tl¡ml_-4/l.ðôl Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: & R; ;kJ~ I- t ~I:. \\\((({{(f((r. \,-'- ~"( BULl. fr,r \.\. rv~ - . . . .. 0 "/- ~~ .. ---.. ('1-;:" ~ :·~OTA~¡'·.1--~ ,,-. --. :::. § : PUBL\C :=. . ~ --- .&-: ~ .- "S"A. ~"'. ~ S .: ~-OF AL~ . . ~ ~ '. ..- ......\"\ /..// * \ \"\ . }})J}))}))ì. ....... ....... -;:",( and 'Ga¿C on se rvolion Commission, 333 West 7th I Avenue, Suite 100, An- 'I charage, Alaska 99S01. In I additian, a person mÇlY 'I submit a written protest or camments on the ap- , pllcatlons prlar to May 7, 2001 at 9:00 am. I .. Ifyou,are,aperson,with a:diso,bl.llty who may I ,~~~d.r~~~:i~~~Tg~I~~~t . or to attend the public' I 'he,arin9, please contact JoðyColombie at 793~1221 : befor,e M~y 1, 200~. ' Is/Camille' Oechsll Taylar Commissloher ,'", Pub;;' Å:ril'S, 20Q1 AO# 02114014 AO.FRM PUBLISHER 02-901 (Rev. 3/94) Page 2 Notary public for state of My commission expires 19_, day of This Subscribed and sworn to before me excess of the rate charged private individuals. , 1 9 I and that the rate charged thereon is not in day of _ consecutive days, the last publication appearing on the 1 9_, and thereafter for day of the annexed is a true copy, was published in said publication on the_ and that the advertisement, of which _and state of in said division Published at of says that he/she· is the who, being first duly sworn, according to law, 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. Before me, the undersigned, a notary public this day personally appeared_ division. ss State of AFFIDAVIT OF PUBLICATION REMINDER United states of America SPECIAL INSTRUCTIONS: THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. DATE OF A.O. AGENCY CONTACT Jody Colombie PHONE (907) 793 -1221 DATES ADVERTISEMENT REQUIRED: April 5, 2001 ~ Anchorage, Daily News POBox 149001 Anchorage, AK 99514 April 4. 2001 PCN AOGCC R 3001 Porcupine Drive o Anchorage, AK 99501 M F .) NOTICE TO PUBLISHER I ) ADVERTISING ORDER NO. II. MUST BE IN TRJPLlCATE SHOWING ADVERTISING ORDE~.. ŒRTlFIED 0 AFFIDAVIT OF PUBLICATION (PART2 OF THIS FORM) WITH ATTACHED COpy OF AO- 2114014 ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE STATE OF ALASKA ADVERTISING ORDER , . seE B9TI<?~ :F~~ 1NV~,C~ 'ADDRESS:, Page 1 ACE PETROLEUM COMPANY AK JOURNAL OF COMMERCE OIL & INDUSTRY NEWS ALASKA DEPT OF LAW ALASKA OFC OF THE GOVERNOR ALASKA OIL & GAS ASSOC AL YESKA PIPELINE SERV CO AL YESKA PIPELINE SERV CO LEGAL DEPT AL YESKA PIPELINE SERV CO AL YESKA PIPELINE SERVICE CO VALDEZ CORP AFFAIRS AMERICA/CANADIAN STRATIGRPH CO 4/4/01 () AddrConsOrd ~) ~) AddrConsOrd () 4/4/01 GEORGE G VAUGHT JR SENATOR LOREN LEMAN JOHN MILLER RICHARD FINEBERG FRED PRATT RAY TYSON C BURGLlN RICK WAGNER DIANE SUCHOMEL JOHN A LEVORSEN POBOX 13557 STATE CAPITOL RM 113 3445 FORDHAM DR POBOX 416 POBOX 72981 2016 MAIN #1415 POBOX131 POBOX 60868 105070 W MAPLEWOOD DR 200 N 3RD ST #1202 PENNY V ADLA POBOX 467 JERRY HODGDEN GEOL 40818TH ST DUSTY RHODES 229 WHITNEY RD RON DOLCHOK POBOX 83 R E MCMILLEN CONSULT GEOL 202 E 16TH ST DAVID CUSATO 600 W 76THAV #508 WATTY STRICKLAND 2803 SANCTUARY CV L G POST O&G LAND MGMT CON 10510 Constitution Circle ANTONIO MADRID POBOX 94625 H L WANGENHEIM 5430 SAWMILL RD SP 11 BAPI RAJU 335 PINYON LN ROBERT G GRAVELY 7681 S KIT CARSON DR JAMES GIBBS POBOX 1597 ALFRED JAMES III 107 N MARKET STE 1000 DAVID W. JOHNSTON 320 MARINER DR. JAMES E EASON 8611 LEEPER CIRCLE ARMAND SPIELMAN 651 HILANDER CIRCLE NANCY LORD PO BOX 558 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST NICK STEPOVICH 543 2ND AVE GORDON J. SEVERSON 3201 WESTMAR CIR JAMES RODERICK PO BOX 770471 MARK ALEXANDER 7502 ALCOMITA ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR JACK 0 HAKKILA POBOX 190083 GERALD GANOPOLE CONSULT 2536 ARLINGTON ANDREW C CLIFFORD PO BOX 79593 ROSE RAGSDALE 4220 B Street Ste #210 ROBERT E MINTZ ASST ATTY G 1031 W 4TH AV STE 200 JOHN KATZ STE 518 444 N CAPITOL NW JUDY BRADY 121 W FIREWEED LN STE 207 PERRY A MARKLEY 1835 S BRAGAW - MS 575 1835 S BRAGAW 1835 S BRAGAW - MS 530B POBOX 300 MS/701 4800 KUPREANOF CHUCK O'DONNELL SANDY MCCLINTOCK RON BROCKWAY Page 2 DENVER JUNEAU ANCHORAGE ESTER FAIRBANKS HOUSTON FAIRBANKS FAIRBANKS LITTLETON BOISE CO AK AK AK AK TX AK AK CO 10 NINILCHIK AK GOLDEN CO ANCHORAGE AK KENAI AK OWASSO OK ANCHORAGE AK KATY TX EAGLE RIVER AK PASADENA CA PARADISE CA ,COPPELL TX LITTLETON CO SOLDOTNA AK WICHITA KS ANCHORAGE AK ANCHORAGE AK ANCHORAGE AK HOMER AK ANCHORAGE AK FAIRBANKS AK ANCHORAGE AK EAGLE RIVER AK HOUSTON ' TX ANCHORAGE AK ANCHORAGE AK ANCHORAGE AK HOUSTON TX ANCHORAGE AK ANCHORAGE AK WASHINGTON DC ANCHORAGE AK ANCHORAGE AK ANCHORAGE AK ANCHORAGE AK VALDEZ AK ANCHORAGE AK 6,) AddrConsOrd () 4/4/01 AMOCO CORP 2002A AMSINALLEE CO INC ANADARKO ANADRILL-SCHLUMBERGER ANCHORAGE DAILY NEWS ANCHORAGE TIMES ARENT FOX KINTNER PLOTKIN KAHN ASRC ASRC BABCOCK & BROWN ENERGY, INC. BABSON & SHEPPARD BAKER OIL TOOLS BELOWICH BONNER & MOORE BP EXPLORATION (ALASKA) INC BP EXPLORATION (ALASKA) INC BP EXPLORATION (ALASKA) INC BP EXPLORATION (ALASKA) INC BP EXPLORATION (ALASKA), INC. BRISTOL ENVIR SERVICES C & R INDUSTRIES, INC., CHEVRON CHEVRON CHEM CO CHEVRON USA INC. CIRI COOK INLET KEEPER CROSS TIMBERS OIL COMPANY CROSS TIMBERS OPERATIONS D A PLATT & ASSOC DEGOL YER & MACNAUGHTON DEPT OF ENVIRON CONSERV SPAR DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF NATURAL RESOURCES DEPT OF REVENUE DEPT OF REVENUE DEPT OF REVENUE DEPT OF REVENUE DEPT OF REVENUE DNR DOCUMENT SERVICE CO DPC LIBRARY/INFO CTR EDITORIAL PG EDTR LIBRARY JULIE WEBER ALASKA AREA MGR LIBRARY H20 INFO RESOURCE CTR MB 3-2 LIBRARY & INFO CTR ALASKA DIVISION LAND DEPT MIDCONTINENT DIVISION DIV OF OIL & GAS DIV OF OIL & GAS PUBLIC INFORMATION CTR DIV OF OIL & GAS DIV OIL & GAS DIV OF OIL & GAS DIV OF LAND DGGS OIL & GAS AUDIT OIL & GAS AUDIT DIV OF OIL & GAS Page 4 '-) AddrConsOrd () 4/4/01 WILLIAM 0 VALLEE PRES MARK HANLEY MICHAEL CAREY BERT TARRANT WASHINGTON SQ BLDG CONRAD BAGNE BILL THOMAS 600 17TH STREET JOHN F BERGQUIST MICHAEL A BELOWICH SUE MILLER MR. DAVIS, ESQ PETE ZSELECZKY LAND MGR MARK BERLINGER MB 8-1 JIM MUNTER KURT SALTSGAVER PAUL WALKER ATTN: CORRY WOOLlNGTON BOB SHAVELSON MARY JONES SUSAN LILLY ONE ENERGY SQ, STE 400 CHRIS PACE JIM STOUFFER TIM RYHERD JULIE HOULE WILLIAM VAN DYKE BRUCE WEBB REG MGR NORTHERN REGION JOHN REEDER DAN DICKINSON, DIRECTOR CHUCK LOGSTON DENISE HAWES FRANK PARR BEVERLY MARQUART JAMES B HAYNES NATURAL RE JOHN PARKER DANIEL DONKEL POBOX 87703 CHICAGO IL PO BOX 243086 ANCHORAGE AK 3201 C STREET STE 603 ANCHORAGE AK 3940 ARCTIC BLVD #300 ANCHORAGE AK POBOX 149001 ANCHORAGE AK POBOX 100040 ANCHORAGE AK 1050 CONNECTICUT AV NW WASHINGTON DC 301 ARCTIC SLOPE AV STE 300 ANCHORAGE AK POBOX 129 BARROW AK STE. 2630 SOUTH TOWER DENVER CO POBOX 8279 VIKING STN LONG BEACH CA 4710 BUS PK BLVD STE 36 ANCHORAGE AK 1125 SNOW HILL AVE WASILLA AK 2727 ALLEN PKWY STE 1200 HOUSTON TX POBOX 196612 MIS LR2-3 ANCHORAGE AK POBOX 196612 MB 13-5 ANCHORAGE AK POBOX 196612 ANCHORAGE AK POBOX 196612 ANCHORAGE AK PO BOX 196612 ANCHORAGE AK 2000 W. INT'L AIRPORT RD #C-1 ANCHORAGE AK 7500 W MISSISSIPPI AVE STE C4 LAKEWOOD CO 1301 MCKINNEY RM 1750 HOUSTON TX POBOX 2100 HOUSTON TX POBOX 1635 HOUSTON TX POBOX 93330 ANCHORAGE AK POBOX~~ HOMER AK 810 HOUSTON ST STE 2000 FORT WORTH TX 210 PARK AVE STE 2350 OKLAHOMA CITY OK 9852 LITTLE DIOMEDE CIR EAGLE RIVER AK 4925 GREENVILLE AVE DALLAS TX 410 WILLOUGHBY AV STE 105 JUNEAU AK 550 W 7TH AVE, SUITE 800 ANCHORAGE AK 550 W 7th AVE STE 800 ANCHORAGE AK 550 W 7TH AVE, SUITE 800 ANCHORAGE AK 550 W 7TH AVE, SUITE 800 ANCHORAGE AK 550 W 7TH AVE, SUITE 800 ANCHORAGE AK 550 W 7TH AVE, SUITE 800 ANCHORAGE AK 3700 AIRPORT WAY FAIRBANKS AK POBOX 772805 EAGLE RIVER AK 550 W 7TH AVE, SUITE 500 ANCHORAGE AK 550 W 7TH AVE, SUITE 500 ANCHORAGE AK 550 W 7TH AV STE 570 ANCHORAGE AK 550 W 7TH AVE STE 570 ANCHORAGE AK 550 W 7TH AV STE 570 ANCHORAGE AK 550 W 7TH AVE, SUITE 800 ANCHORAGE AK POBOX 1468 KENAI AK 1420 NORTH ATLANTIC AVE, ST DAYTON BEACH FL Page 5 &.,) AddrConsOrd () 4/4/01 ECONOMIC INSIGHT INC ENERGY GRAPHICS ENSTAR NATURAL GAS CO EXXON EXPLOR CO EXXON EXPLORATION CO. EXXONMOBIL PRODUCTION COMPANY EXXONMOBIL PRODUCTION COMPANY EXXONMOBIL PRODUCTION COMPANY FAIRBANKS DAILY NEWS-MINER FAIRWEATHER E&P SERV INC FINK ENVIRONMENTAL CONSULTING, I FORCENERGY INC. GAFFNEY, CLINE & ASSOC., INC. GAFO GUESS & RUDD H J GRUY HALLIBURTON ENERGY SERV HDR ALASKA INC ILLINOIS STATE GEOL SURV INTL OIL SCOUTS IOGCC JWL ENGINEERING K&K RECYCL INC KENAI NATL WILDLIFE REFUGE KENAI PENINSULA BOROUGH LA PUBLIC LIBRARY LIBRARY OF CONGRESS LINDA HALL LIBRARY MARATHON MARATHON OIL CO MARATHON OIL CO MARATHON OIL CO MARPLES BUSINESS NEWSLETTER MUNGER OIL INFOR SERV INC MURPHY E&P CO N-I TUBULARS INC NORTHERN CONSULTING GROUP NRG ASSOC NY PUBLIC LIBRARY DIV E OIL & GAS JOURNAL OIL & GAS JOURNAL OPSTAD & ASSOC ORO NEGRO, INC. PACE PENNZOIL E&P PETRINFO PETRAL CONSULTING CO LAND/REGULATORY AFFAIRS RM 301 LIBRARY GREENPEACE LIBRARY REFUGE MGR ECONOMIC DEVEL DISTR SERIALS DIV STATE DOCUMENT SECTION SERIALS DEPT OPERATIONS SUPT GRAND CENTRAL STATION Page 7 ,) AddrConsOrd (} 4/4/01 POBOX 683 1600 SMITH ST, STE 4900 POBOX 190288 POBOX 4778 POBOX 4778 POBOX 2180 POBOX 2180 PO BOX 196601 POBOX 70710 715 I ST #4 6359 COLGATE DR. 310 K STREET STE 700 16775 ADDISON RD, STE 400 125 CHRISTENSEN DR. #2 510 L ST, STE 700 1200 SMITH STREET STE 3040 6900 ARCTIC BLVD 2525 C ST STE 305 615 E PEABODY DR POBOX 338 POBOX 53127 9921 MAIN TREE DR. POBOX 58055 POBOX 2139 POBOX 3029 630 W 5TH ST 10 FIRST ST SE 5109 CHERRY ST POBOX 3128, Ste 3915 POBOX 196168 BRAD PENN POBOX 196168 GEORGE ROTHSCHILD JR RM 25 POBOX 4813 MICHAEL J PARKS 117 W MERCER ST STE 200 POBOX 45738 POBOX 61780 3301 C Street Ste 209 2454 TELEQUANA DR. POBOX 1655 POBOX 2221 1700 W LOOP SOUTH STE 1000 POBOX 1260 POBOX 190754 9321 MELVIN AVE POBOX 2018 POBOX 2967 POBOX 1702 9800 RICHMOND STE 505 SAM VAN VACTOR MARTY LINGNER BARRETT HATCHES T E ALFORD GARY M ROBERTS RM 3039 J W KIKER ROOM 2086 MARK P EVANS KATE RIPLEY JESSE MOHRBACHER THOMAS FINK, PHD JIM ARLINGTON PAMELA MILLER GEORGE LYLE ATTN: ROBERT RASOR MARK WEDMAN MARK DALTON 469 NATURAL RESOURCES BLD MASON MAP SERV INC JEFF LIPSCOMB STAN STEADMAN EXCH & GIFT DIV Ms. Norma L. Calvert ROBERT F SAWYER - ROBERT BRITCH, P.E. RICHARD NEHRING BOB WILLIAMS LAURA BELL ERIK A OPSTAD PROF GEOL SHEILA DICKSON WILL D MCCROCKLIN DAVID PHILLIPS DANIEL L LIPPE Page 8 PORTLAND OR HOUSTON TX ANCHORAGE AK HOUSTON TX HOUSTON TX HOUSTON TX HOUSTON TX ANCHORAGE AK FAIRBANKS AK ANCHORAGE AK ANCHORAGE AK ANCHORAGE AK ADDISON TX ANCHORAGE AK ANCHORAGE AK HOUSTON TX ANCHORAGE AK ANCHORAGE AK CHAMPAIGN IL AUSTIN TX OKLAHOMA CITY OK ANCHORAGE AK FAIRBANKS AK SOLDOTNA AK KENAI AK LOS ANGELES CA WASHINGTON DC KANSAS CITY MO HOUSTON TX ANCHORAGE AK ANCHORAGE AK HOUSTON TX SEATTLE WA LOS ANGELES CA NEW ORLEANS LA ANCHORAGE AK ANCHORAGE AK COLORADO SPRI CO NEW YORK NY HOUSTON TX TULSA OK ANCHORAGE AK NORTHRIDGE CA SOLDOTNA AK HOUSTON TX HOUSTON TX HOUSTON TX E~~JJ1J*~~';~'~:~ti;'-<;'CÞ'M,PAMY':i~ .:::·}:::::'f~:.::~:i"::~;'\~~H:;!:~;:~'&~.:.a;±:Z1~;t.iX~~:::!:;¡.~L:;',~~~,PÂB!.Ms~L~¡:~2)~t~~~ PETROLEUM INFO CORP PHILLIPS ALASKA PHILLIPS ALASKA PHILLIPS ALASKA PHILLIPS ALASKA PHILLIPS ALASKA PHILLIPS ALASKA PHILLIPS ALASKA PHILLIPS PETR PHILLIPS PETR CO PHILLIPS PETR CO PHILLIPS PETR CO PHILLIPS PETR CO PHILLIPS PETROLEUM COMPANY PINNACLE PIRA ENERGY GROUP LIBRARY PRESTON GATES ELLIS LLP LIBRARY PURVIN & GERTZ INC LIBRARY REGIONAL SUPRVISOR, FIELD OPERAT MMS RUB ICON PETROLEUM, LLC SD DEPT OF ENV & NATRL RESOURCES OIL & GAS PROGRAM SHELL WESTERN E&P INC SHIELDS LIBRARY STANDARD AMERICAN OIL CO STATE PIPELINE OFFICE TAHOMA RESOURCES TECHSYS CORP TESORO PETR CORP TEXACO INC TEXACO INC TRADING BAY ENERGY CORP TRUSTEES FOR ALASKA U S DEPT OF ENERGY UNIV OF ALASKA FAIRBANKS UNIV OF ALASKA FBX UNIV OF ARKANSAS UNIVERSITY OF ALASKA FBKS UNOCAL UNOCAL UNOCAL UOAl ANCHORAGE US BLM AK DIST OFC US BUREAU OF LAND MGMT US BUREAU OF LAND MNGMNT US BUREAU OF LAND MNGMNT US DEPT OF ENERGY US EPA REGION 10 Page 10 INST OF SOCIAL & ECON RESEARCH RESOURCE EVAL GRP OIL & GAS OPRNS (984) ANCHORAGE DIST OFC ANCHORAGE DIST OFC ENERGY INFORMATION ADMINISTRATIO REVENUE ACCOUNTING PETR DEVEL LAB PETR DEVEL LAB SERIALS DEPT PETR DEVEL LAB Portfolio Team Manager LIBRARY GOVT DOCS DEPT ALASKA OPERATIONS MANAGER PARTNERSHIP OPRNS LAND DEPT LEGAL DEPT KUP CENTRAL WELLS ST TSTNG LIBRARY 4/4/01 () AddrConsOrd ~) &.) AddrConsOrd (J 4/4/01 KRISTEN NELSON POBOX 102278 ANCHORAGE AK JAMES WINEGARNER POBOX 10036 ANCHORAGE AK MARK P WORCESTER POBOX 100360 ANCHORAGE AK WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE AK POBOX 100360 ANCHORAGE AK STEVE BENZLER A TO 1404 POBOX 100360 ANCHORAGE AK JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE AK MARK MAJOR A TO 1968 POBOX 100360 ANCHORAGE AK J W KONST P 0 DRAWER 66 KENAI AK JIM JOHNSON 6330 W LOOP S RM 1132 BELLAIRE TX JOE VOELKER 6330 W LP S RM 492 BELLAIRE TX ERICH R. RAMP 6330 W LOOP SOUTH BELLAIRE TX ALASKA LAND MGR POBOX 1967 HOUSTON TX W ALLEN HUCKABAY PO BOX 1967 HOUSTON TX STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER AK 3 PARK AVENUE (34th & PARK) NEW YORK NY 420 L ST STE 400 ANCHORAGE AK 2150 TEXAS COMMERCE TWR 600 TRAVIS ST HOUSTON TX ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE AK BRUCEICLARDY SIX PINE ROAD COLORADO SPRI CO 2050 W MAIN STE #1 RAPID CITY SD G.S. NADY POBOX 576 HOUSTON TX UNIV OF CALIF DAVIS CA AL GRIFFITH POBOX 370 GRAN BURY TX KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE AK GARY PLAYER 1671 WEST 546 S CEDER CITY UT BRANDY KERNS PO BOX 8485 GATHERSBURG MD LOIS DOWNS 300 CONCORD PLAZA DRIVE SAN ANTONIO TX R W HILL POBOX 5197x Bakersfield CA R Ewing Clemons PO BOX 430 BELLAIRE TX PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE AK 1026 W. 4th Ave, Ste 201 ANCHORAGE AK PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON DC DR V AKAMATH 427 DUCKERING FAIRBANKS AK SHIRISH PATIL 437 DICKERING FAIRBANKS AK UNIV LIBRARIES FAYETTEVILLE AR DR AKANNI LAWAL POBOX 755880 FAIRBANKS AK POBOX 196247 ANCHORAGE AK POBOX 4531 HOUSTON TX KEVIN TABLER POBOX 196247 ANCHORAGE AK TERESA HULL 3211 PROVIDENCE DR ANCHORAGE AK ART BONET 6881 ABBOTT LOOP RD ANCHORAGE AK J A DYGAS 222 W 7TH AV #13 ANCHORAGE AK PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE AK DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE AK MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS TX THOR CUTLER OW-137 1200 SIXTH AVE SEATTLE WA Page 11 ~) AddrConsOrd () 4/4/01 US GEOLOGICAL SURVEY US GEOLOGICAL SURVEY US GEOLOGICAL SURVEY US GEOLOGICAL SURVEY US MIN MGMT SERV US MIN MGMT SERV US MIN MGMT SERV US MIN MGMT SERV US MIN MGMT SERV US MIN MGMT SERV US MIN MGMT SERV USGS - ALASKA SECTION VALDEZ PIONEER VALDEZ VANGUARD WORLD OIL YUKON PACIFIC CORP LIBRARY LIBRARY LIBRARY RESOURCE STUDIES AK OCS REGN CHIEF OCS STATS & INFO LIBRARY AK OCS REGIONAL DIR RESOURCE EVAL LIBRARY EDITOR Page 13 Page 14 BOX 25046 MS 914 DENVER CO KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK CA 2255 N GEMINI DR FLAGSTAFF AZ NATIONAL CTR MS 950 RESTON VA KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE AK 381 ELDEN ST MS 4022 HERNDON VA FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE AK 949 E 36TH A V RM 603 ANCHORAGE AK 949 E 36TH AV RM 110 ANCHORAGE AK RICHARD PRENTKI 949 E 36TH AV ANCHORAGE AK JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE AK 4200 UNIVERSITY DR ANCHORAGE AK POBOX 367 VALDEZ AK POBOX 98 VALDEZ AK DONNA WILLIAMS POBOX 2608 HOUSTON TX JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE AK 4/4/01 () AddrConsOrd ~) &' () Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Meltwater Oil Pool, Kuparuk River Field - Pool Rules and Area Injection Order PHILLIPS Alaska, Inc. by letter dated March 12, 2001, has applied for an area injection order and pool rules under 20 AAC 25.460 and 20 AAC 25.520, respectively, to enable development of the Meltwater Oil Pool, Kuparuk River Field, on the North Slope of Alaska. A person may submit a written protest or written comments on the requested exemption prior to 4:00 PM on April 25, 2001 to the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501. In addition, the Commission has tentatively set a public hearing for April 25, 2001 at the Alaska Oil and Gas Conservation Commission, 333 W. 7th, Suite 100, Anchorage, Alaska. A person may request that the tentatively scheduled hearing be held by filing a written request with the Commission prior to 4:00 PM on April 12, 2001. If a request for a hearing is not timely filed, the Commission will consider the issuance of an order without a hearing. To learn if the Commission will hold the tentative hearing, please call 793 -1221. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Jody Colombie at 793-1221 before April 18, 2001. ~4ùG ~W-. ~ Camil1é Oechsli Taylor Commissioner Published March 23, 2001 ADN AO# 02114013 () r-) Anchorage Daily News$/291~OQ1 Affidavit of Publication 1001 Northway Drive, Anchorage, AK 99508 PRICE OTHER OTHER GRAND AD# DATE PO ACCOUNT PER DAY CHARGES CHARGES #2 TOTAL 807914 03/23/2001 02114013 STOF0330 $94.17 $0.00 $0.00 $94.17 $0.00 $0.00 $0.00 $94.17 $0.00 $0.00 $94.17 ~ :23,;2ðIJ / STATE OF ALASKA , Alaska 011" and Gas· ,. Conservation Commission Re: Meltwater Oil Pool, Kuparuk River Field - Pool Rule,s and Area In- lectlon, .Order PHILLIPS Alaska, Inc'" by letter dated March 12, , 2001-, has applied for an area injection order and , pool rules under 20 ÄAC : 25.460 and' 2Q AAC 25.520, , respectively, tp enable ~ de vel 0 P me n t . Of the I Meltwater 011 Pool, Ku- , paruk,R'iver,Fièll:l; on the , North Slope of Alaska. ' I A person may submit a , wrlttel1:protes,-or wrlt- ¡ten comm,'nts on the're- I quested exemption, prior , to 4:,OO.PM an,Aprll,25, : 2001 to· the Alaska 0/1 'and ; Gas Conservation Com- mission, 3001 Porcupine , Drive, Anchorage, Alaska , : 99501. 'In addltlo,n, ,the Commission has tenta- tively set: a public 'hear- Ing for April 25, 2001 at the Alaska Oil and Gas Conservation Commis- sion, 333 W. 7th Avenue, I Suite 100, Ancho·rage, I Alaska. A person may 're- , quest that the ,tentativelY, scheduled'hearlng be held I by fill n9 a written re- quest with the Com mls- : sian prior fa, 4:00 PM on, April ,12; ~OOl. . . If!c:ii:r::~~~·e~t:foÍ""a,:,.,eàr;.. ,ing is.' nortimelyJUed,the COT\r:nts(;lon,wHI con- si(Ìerthe l~suaqClir of. an orderw.ltho/./t,,, hearln,"" Tol,earn .iftheCo.mmls~ s ion,WllI'holçl'the. t,~1Ìta,~ t Ive,hea ring,p leäsè,call 793-'1221.': ' , ' ' 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 asa daily newspaEer in Anchorage, Alaska, and it is now and during all saia 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 for the fore~oing publication is not in excess of the rate charged private indIviduals. Signed 2uc,-----, Q~~ Subscribed and sworn to me before this date: Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: /é.6 S; ~ f \\.{(Urr(fll" \. \. \. \ ~ "<. . ~ ~ l.( I" /'r/r .:::"-~~., ___'. .0" ~ ~ ~_-~OTAR~·_1-~ '-- --- - '-- ...... ...... If YOU arl'a Dl'r<>on with , á di'ilaDlllty who may nE'E-d 0 sDl'clal modifica· tionln order,to comm~nt or to attend thep/./bllc ; hearing, 'please contact ; Jody Colombie at 793-1221 \ before April 18, 2001., , ~ "Is/Camille Òechsll TOYlor Commissioner ,. '. '. /!2u1Ld) AO-D21140,13 ' Pub.: March 23, 2001 - PUBL\C -- ~ ". ~ .~: ~ -::- "9À. ":J" . " -S -: ~- OF þ.\..to: .' <~' ././ ,'\' /./.J *, \ \ \ ' ))}))}}J),i," #1 ) ) PHilliPS Alaska, Inc. A Subsidiary of PHilLIPS PETROLEUM COMPANY Post Office Box 100360 700 G Street Anchorage, Alaska 99510 Telephone 907 265-6806 Ryan Stramp, Meltwater Coordinator March 12, 2001 RECEIVED MAR 1 2 2001 Alaska Oil & Gas C ons Com . AnChorag~ mission Ms. Julie Heusser, Mr. Dan Seamount and Ms. Cammy Taylor Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Re: Meltwater Area Injection Order 20 AAC 25.402 Dear Commissioners: Phillips Alaska, Inc. (PAl) is pursing development of the Meltwater Reservoir through an expansion of the Kuparuk River Unit. (Parallel efforts to expand the Kuparuk River Unit and formulate pool rules to facilitate Meltwater Reservoir development are in progress.) PAl briefed the Commission on Meltwater during a January 30, 2001 meeting. PAl in its capacity as operator submits this letter as an application for Alaska Oil and Gas Conservation Commission approval to conduct an enhanced recovery operation involving MWAG (i.e., alternating water and miscible gas injection), consistent with 20 AAC 25.402 (a). Approval of this application would permit these operations to be conducted in the Meltwater Pool within the initial area targeted for development. The following attachments are submitted pursuant to 20 AAC 25.402 (c): 1. Plat with location of all existing wells that penetrate the injection zone within one- quarter mile of the area covered by this application 2. List of operators and surface owners within one-quarter mile of the proposed injection operations 3. Affidavit showing the operators and surface owners within one-quarter mile of the area affected by the Meltwater Area Injection Order have been provided a copy of this application 4. Full description of the proposed operation 5. Description, depth, and name of the pool to be affected 6. Description of the formation into which fluids are to be injected and the associated confining zones 7. Type well log 8. Casing description and proposed method for testing injection well casing 9. Injection fluid data 10. Estimated pressures 11. Evidence and data to support a commission finding that injection wells will not initiate or propagate fractures through the overlying strata 12. Analysis of the water within the formation Phillips Alaska, Inc. is a subsidiary of Phillips Petroleum Company ) ) " 13. Reference to applicable freshwater exemption issued under 20 AAC 25.440 14. Incremental increase in ultimate hydrocarbon recovery. 15. Mechanical condition of each well that has penetrated the proposed injection zone within a one-quarter mile radius of the Meltwater Oil Pool. I appreciate your work on this application and would be happy to answer any related questions. I can be reached at 265-6268 or rstramp@ppco.com via email. Sincerely, ~O-r, S~~ Ryan Stram p Meltwater Coordinator cc: Mike Kotowski RECErVED MAR 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 2/29 ) ) Meltwater Area Injection Order Attachment 1 20 AAC 25.402 (c)(1) Plat of Wells Penetrating Iniection Zone The attached map (Attachment 1 A) shows all existing wells that penetrate the injection zone in the proposed injection area. The map also shows Meltwater Reservoir seismic anomalies and the proposed Kuparuk River Unit expansion area. Although the exact acreage of the expansion has not yet been finalized, this map shows its largest possible extent based on current expansion efforts. In addition, the map shows Meltwater development wells (with their expected initial service) planned to be drilled during 2001 and 2002 and Meltwater exploratory well penetrations. Initial well location and service plans will likely change as net pay and well performance data are gathered. The total number, type and locations of wells ultimately drilled into the Meltwater Pool will also be a function of net pay and well performance data. Since Meltwater Reservoir distribution is stratigraphically controlled and sand accumulations are localized, sand continuity is expected to be difficult to predict. Producer/Injector interactions will likely be difficult to predict in the absence of field data. Development plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injection service as necessary in order to provide pressure support and minimize injectant cycling. Hence, to as large of an extent as possible, plans are to let reservoir performance be a guide in optimizing pattern configurations. Although initial development plans do not include a Class II disposal well, future needs may eventually require one. The Ivishak Sandstone of the Sadlerochit Group has been selected, if needed. This zone is expected to have at least 60 feet of sandstone with porosities greater than 15% in the vicinity of the Meltwater Participating Area. The Ivishak depth is expected to be approximately 8500 feet subsea. Several exploration wells have been drilled to this horizon in the vicinity of the Meltwater Participating Area, in particular, the Union Kookpuk, Union Itkillik River and Sinclair Colville wells. The Ivishak Sandstone was wet in each of these wells and is therefore also expected to be wet in the vicinity of the Meltwater Participating Area wells (see Sinclair Colville log section, Attachment 11 c). The Ivishak Sandstone, as well as the overlying Shublik Formation and Sag R. Sandstone, was wet in each of these wells. This zone is therefore also expected to be wet in the vicinity of the Meltwater Participating Area. The Ivishak Sandstone is separated from the overlying Kuparuk River Formation by approximately 1800 feet of shales of the Kingak Formation, as well as approximately 400 feet of Shublik and Sag River Sandstone. RE.CEiVED MAR 1 2 2001 Alaska Oil & Gas Cons, Commission Anchorage Meltwater Area Injection Order Page 3/29 ) ) Meltwater Area Injection Order Attachment 2 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Iniection Operations Operator: Phillips Alaska, Inc. Attention: Dan Kruse A TO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owner: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 RECErv?ED MAR 1 2 2001 ,,A,laska Oil & Gas Cens, Commission Anchorage Meltwater Area Injection Order Page 5/29 ) Meltwater Area Injection Order Attachment 3 20 AAC 25.402 (c)(3) Affidavit of Ryan L. Stramp Regarding Notice to Suñace Owners Ryan L. Stramp, on oath, deposes and says: 1. I am the Meltwater Coordinator at Phillips Alaska, Inc., the designated operator of the Kuparuk River Unit (which will include the Meltwater Pool). 2. On March 12, 2001, I caused copies of the Area Injection Order Application to be provided to the surface owner and operator of all land within a quarter mile of the unit as listed below: State of Alaska Department of Natural Resources Attention: Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 Phillips Alaska, Inc. Attention: Dan Kruse ATO-1220 P.O. Box 100360 Anchorage, AK 99510-0360 ~t7n L__ 'S~~ I J kyan L. Str~ , STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this 12th day of March, 2001. \ \ \ l [ [ ( ( ( ( ( ( (/. \.\. \. \. ;"\ ~. ~: tt 0(, r,r..;.. ,\: -")..~ .' - - - '. <.ð."" ............ ,- . . v' ,.,. ~ ~",,"OTAI\»i:.~S ........~. --. .....~ ~ : ÞUBL\C :%~ ~ *. . *-.. -' . . ~ --. . =" -:::. ~C". . . :Y ~ :,~>,:,. . . . . ~~ :\' -'<)/~~OF A\."~ ,\' -J/J)))))))ì" ??~Æ- lLOG ~t;, . ~ 1 NO lAkY PU~LlC IN ÀNLfi:ôkALÄ~KA My Commission Expires: <6Í\ 6(-ZCo( RECEiVED MAR 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 6/29 } } RECEiVED Meltwater Area Injection Order MAR 1 2 2001 Attachment 4 20 AAC 25.402 (c)(4) Alaska Oil & Gas Cons. Commission Anchorage Description of the Proposed Operation The Meltwater Area Injection Order is needed to develop the Meltwater Reservoir. The expected scope of the current development project involves drilling approximately 26 wells to develop 52 MMBO associated with an estimated 132 MMBO original oil in place (001 P) seen by existing exploratory wells in the Bermuda Interval of the Meltwater Reservoir. Although Attachment 1 A shows 41 penetrations, this is considered an upside case. Field Development Development wells will be drilled from a single new drill site. Initial development drilling operations are planned to start during the second quarter of this year. The drilling program will initially focus on developing the main portion of the reservoir and testing the periphery. Well performance data and improved seismic calibrations acquired from the initial development wells will help guide the extent of the overall development drilling program. Exploratory drilling targeting other zones within the Meltwater Reservoir will be conducted concurrently with development drilling operations. Successful exploratory drilling results could alter existing plans by (1) changing the location and target interval of the initial development wells and (2) expanding the scope of the project to include additional wells. An expanded project scope would likely involve additional development drilling phases and may require an areal expansion of the proffered Meltwater Area Injection Order. Recovery Mechanism Initially employing an MW AG recovery process, which consists of alternating cycles of water and MI, is a key aspect of the planned development. Following are the main reasons for the 1. Numerical simulation indicates that MW AG provides higher recoveries than any other competing recovery process (i.e., primary drainage, waterflood, miscible gas flood, and lean gas flood). For example, simulation results suggest that an MW AG process, with a 20% cumulative hydrocarbon pore volume slug of injected miscible gas, would provide an incremental recovery of 9% 001 P compared to a waterflood process. 2. Enriched natural gas used at Kuparuk is miscible with Meltwater fluids at reservoir conditions. (Henceforth in this document, enriched natural gas will be referred to as "MI" for Miscible Injectant.) This is supported by slim tube simulation results and is consistent with actual slim tube experiments run on Tarn crude. (Given that the composition of Meltwater and Tarn crudes are very similar, they should behave in a similar fashion from a phase behavior and fluid displacement standpoint.) Meltwater Area Injection Order Page 7/29 )ì } 3. Greater Kuparuk Area (GKA) MI is currently piped to offset Tarn Drill Site 2N and is transportable to Meltwater for a relatively small premium. 4. Initially pursing MWAG is imperative if this EOR process is to be employed. Meltwater's MI supply is dependent on existing west-end GKA infrastructure. The MW AG floods in this part of the GKA are relatively mature. Delaying implementation of MW AG at Meltwater would therefore jeopardize this project's EOR reserves, as critical GKA infrastructure may not be available in the future to transport MI. (Other potential uses of the GKA MI distribution system include de- bottlenecking production/injection lines and providing high pressure lift gas). After the cumulative target slug size of MI has been injected into the formation, pressure support will be maintained with water injection. Current plans are to eventually inject lean gas into the reservoir to help recover light liquid hydrocarbons (used to manufacture MI) that will be trapped in the reservoir by the MWAG process. Injectant Sources The miscible injectant employed at Meltwater will initially be the same injectant as that currently used at Tarn and the Kuparuk River Unit Large Scale EOR Project. This injectant is manufactured at Kuparuk's CPF-1 and CPF-2 by blending lean gas from the Kuparuk River Unit's production facilities with light hydrocarbon liquid streams from the Prudhoe Bay Unit and Kuparuk River Unit. The light liquid hydrocarbons from the Prudhoe Bay Unit are NGLs from the CGF. The light liquid hydrocarbons from the Kuparuk River Unit consist of scrubber liquids from artificial lift gas compression systems at CPF-1 and CPF-2, NGLs from CPF-1 and naphtha from the Topping Plant. During the flood, there is a possibility that Meltwater produced gas may be blended with Kuparuk River Unit MI to generate a lighter MI blend customized for the Meltwater Reservoir pressure and oil properties. Slim tube simulation results and slim tube experiments on similar (Tarn) crude indicate that Kuparuk MI is richer than needed to achieve miscibility with Meltwater oil at reservoir pressure (2400 psig in the Meltwater #1 well). After the cumulative target slug size of MI has been injected into the formation, pressure support will be maintained with water injection. Current plans are to eventually inject lean gas into the reservoir to help recover light liquid hydrocarbons (used to manufacture MI) that will be trapped in the reservoir by the MWAG process. The source of the lean gas will be Kuparuk River Unit's CPF-2. Potential gas accumulations in the area will also be considered as possible supplemental sources. Rl::CEi\lED MAR 1 2 2001 Alaska Oil & Gas COilS, Comrnissiol~ .A.nchorage Meltwater Area Injection Order Page 8/29 ~ ) Fluid and Cost Allocation Meltwater production will be commingled with Tarn and Kuparuk production in surface facilities prior to final processing and ultimate custody transfer in accordance with the Meltwater Pool Rules (currently being developed). The Greater Kuparuk Area Alignment Agreement, which set new tract ownership and facility sharing terms in the Meltwater area, will help govern business issues associated with sharing infrastructure. A portion of the Meltwater accumulation extends outside the existing GKA onto a PAI/BP lease (see Attachment 4A). All GKA owners, except Exxon-Mobil (with a .3648% GKA working interest), have agreed to buy interest in the lease. Mobil heritage interest was proportionately split between Phillips and BP based on an estimate that 400/0 of total Meltwater reserves are located of this lease. No future production interest adjustments will be made. The resulting Meltwater production interests, pending approval of the Supplemental Provisions, are as follows: Phillips Alaska, Inc. BP Unocal Mobil Chevron 0.55957929 0.39754111 0.03960480 0.00218880 0.00108600 1.00000000 Total RECEfVED MAR 1 2 2001 Alaska Oil & Gas Cons Comm' . , ISSlon ,';nchorage Meltwater Area Injection Order Page 9/29 Attachment 4A Meltwater Accumulation Outside Existing GKA Meltwater Area Order 1 0/29 ) ) Meltwater Area Injection Order Attachment 5 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected The Meltwater Reservoir is the sequence of reservoir sandstones and associated mudstones found in the interval between 4958' and 5368' tvd subsea in the Meltwater North #2A well, and in its lateral equivalents. The Meltwater Reservoir is late Cretaceous in age and stratigraphically within the Seabee Formation. The reservoir is approximately 400' thick and is composed of two intervals. The initial Meltwater Oil Pool includes the entire Meltwater Reservoir, however, the pool definition may change as additional information from development and exploratory activities becomes available. Both Meltwater and Cairn Reservoir intervals are shown in the wireline log from the Meltwater North #2A well (see Attachment 7). Brief summaries of these intervals are given below in descending order. . The 'T4.1', or Cairn Interval, was encountered between 4958' and 5187' tvd subsea in the Meltwater North #2A well. The boundaries are correlatable markers T 4.1 and T3, respectively. Reservoir quality sands were not encountered at this location, but may be present laterally. . The Bermuda Interval was encountered between 5187' and 5297' tvd subsea in the Meltwater North #2A well. The boundaries are correlatable markers T3 and T2, respectively. Hydrocarbon-bearing sands in this interval were encountered in the Meltwater North #2A and in two offset wells. Two Meltwater Reservoir intervals, the Bermuda Interval and Cairn Interval, are sufficiently understood to be included in development plans. Initial injection will be restricted to these two intervals. An expansion of injection operations (both vertically and areally) may be sought in the future depending on results from upcoming drilling activities. RECEi\/ED MAR 1 2 2001 Alaska Oil & Gas Cons. Commission .A.nchorage Meltwater Area Injection Order Page 11/29 '\ J ) Meltwater Area Injection Order Attachment 6 20 AAC 25.402 (c )(6) Description of the Formation The proposed injection zone includes the Cairn Interval and the Bermuda Interval within the Meltwater Oil Pool. This zone lies between 4958' and 5368' tvd subsea in the Meltwater North #2A well (Attachment 7). The Cairn Interval lies between reservoir markers T3 and T 4.1 while the Bermuda Interval lies between reservoir markers T2 and T3. The Meltwater Pool sands are fine- to very fine-grained and have common shale laminations and interbeds. Sands are compositionally heterogeneous: the major components include quartz, heterolithic rock fragments, plagioclase and zeolite. Shale laminations are common. Reservoir sands, which are locally developed within each interval, are lobate to linear in form, and are separated from adjacent reservoirs by mudstones and shales. The top of the Meltwater Reservoir is separated from the Tabasco Sandstone equivalent, the first overlying potential reservoir zone, by a confining layer of approximately 3000' of impermeable shale (Attachment 11 A). The base of the Meltwater Reservoir is separated from the underlying Kuparuk River Formation by approximately 500' of shale. RECEf\J!E:] MAR 1 2 ?001 Alaska Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 12/29 Meltwater Area Injection Order Attachment 7 20 MC 25.402 (c)(7) LOQ of Meltwater Tvpe Well MELTWATER NORTH 2A Meltwater Area Injection Order Page 13/29 ') ) Meltwater Area Injection Order F~E:CEjvrED Attachment 8 MAR 1 2 2001 20 AAC 25.402 (c)(8) /~Iaska Oil & Gas Cons. Commission Anchorage Casing Description and Proposed Method for Testing Casing The proposed casing programs for a typical Meltwater well resembles the casing programs employed in the Kuparuk River Unit (KRU). Although the standard program incorporates maintaining a tubing annulus with isolation and pressure integrity within 200' of the initial producing interval, exceptions to this design criterion will be required to optimize recovery from potentially productive secondary targets. Standard Casing Program As in KRU wells, conductor casing will be set below 75 feet to provide anchorage and support for the rig diverter assembly. The surface casing size may be 9-5/8 or 7-5/8 inch, depending on casing setting depth and production tubing size. Surface casing will be set below the base of the West Sak interval, effectively casing off the permafrost, Ugnu, and West Sak formations. Meltwater wells utilize a tapered casing string tied back to surface, that serves as the combination production casing / tubing string installation. The casing adjacent from the producing interval is the same size as the tubing is at the surface (monobore). The casing across the production interval is then tied back to surface with a string of 3Y2 or 4112 inch tubing inserted into a seal bore or polished bore receptacle (positioned above the top pay zone perforation.) This provides a tubing annulus with isolation and pressure integrity (see diagrams shown in Attachment 8A). There are three casing programs proposed for the Meltwater development: Case 1) 3Y2 inch Slim hole Monobore completions. This casing program utilizes a 7-5/8 inch (L-80, 29.7 pound) surface casing string with a production string of 5Y2 inch (L-80, 15.5 pound) casing crossed over to 3Y2 inch (L-80, 9.3 pound) casing across the Meltwater interval. These monobore wells will be completed with 3112 inch (L-80, 9.3 pound) production tubing. Case 2) 4Y2 inch Monobore completions. This casing program employs 9-5/8 inch (L -80, 40 pound) surface casing with 7 inch (L -80 or J-55, 26 pound) production casing crossed over to 4112 inch (L-80, 12.6 pound) production casing. Case 3) 3Y2 and 4Y2 inch Conventional completions. This casing program employs a string of 9-5/8 inch (L-80, 40.0 pound) casing and an intermediate 7 inch (L- 80 or J-55, 26 pound) intermediate casing string set above the Meltwater formation top. A 3112 inch (L-80, 9.3 pound) or 4112 inch (L-80, 12.6 pound) liner would then be set across the Meltwater formation and tied back to surface with either 3112 inch (L-80, 9.3 pound) or 4112 inch (L-80, 12.6 pound) production tubing. Meltwater Area Injection Order Page 14/29 ) ) Each of these three well types may be completed for either production or injection service. The service of the well will be determined after logging operations. Drilling and completion plans for future Meltwater wells may vary with time as experience and knowledge are gained. The proposed method casing testing method for Meltwater injectors is to follow the requirements of 20 AAC 25.412 (c). Sufficient notice of pressure tests will be given so that a Commission representative may witness the test. Secondary Targets The Bermuda Interval will be the primary target of initial development efforts. Current plans are to focus initial development efforts on that portion of the interval most likely have good reservoir characteristics. As previously shown on Attachment 7, potentially productive secondary targets in the Cairn Interval may be encountered during these development efforts. Secondary targets in the Cairn Interval are expected to generally be within 400' tvd of the Bermuda Interval. These thin, potentially productive zones contain insufficient reserves to merit separate wells or extensive completion design modifications. Although fracture stimulations are planned for Bermuda Interval producers, fracture modeling indicates these stimulations will only grow approximately 100' upwards. Potentially productive secondary pay zones can therefore only be developed if they can be inexpensively commingled with Bermuda production. Given the initial uncertainty of producer/injector interactions, most producers will be candidates for conversion to injection service. In order to maintain conversion flexibility, there are no casing design differences between production and injection wells. (Casing connections will be designed for gas or liquid service.) The flexibility to convert wells to injection service on an as needed basis is an integral part of the Meltwater development strategy. This complicates secondary target development as these targets can only be pursued if they are not isolated by more than one casing string. Pursing secondary targets may result in exceeding the AOGCC guideline that injectors provide annular isolation within 200' measured depth of the highest perforated interval. Plans are to provide annular isolation within 200' measured depth of the perforated lone, unless secondary targets are encountered with a pay thickness approaching or exceeding 10' tvd. Based on current drilling and facility hook-up plans, the productive nature of these secondary targets can not be fully ascertained during initial drilling operations. If future evaluations indicate that developing secondary targets can not be justified, there is the potential of having either current or future injectors with annular isolation located more than 200' measured depth above the perforated zone. Meltwater Oil Pool Rules are written to help ensure that well service flexibility is not sacrificed by attempting to pursue thin secondary targets. ,- - ~E;·'I lfr;;c-\ RElJ ì"V t:U MAR 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 15/29 ') ) Meltwater Area Injection Order Attachment 9 20 AAC 25.402 (c)(9) Injection Fluid Analysis The vast majority of the MI initially employed at Meltwater will originate from Kuparuk River Unit's CPF-2. During 2001, both MI and water will be employed to provide pressure support and maximize sweep. After completing the MW AG recovery process, plans are to eventually inject lean gas into the Meltwater Oil Pool to maximize recovery of the light hydrocarbon liquids that were injected into the reservoir as part of the miscible injectant stream. The source of the lean gas will likely be Kuparuk River Unit's CPF-2. However, other potential gas sources will also be considered. The initial water injection source will be CPF-2 produced water. Local separation and reinjection of water at Meltwater may be considered in the future. Fresh water collected in well cellars from snowmelt may also be injected for short time periods to minimize road traffic during the caribou calving season. The average MI and lean gas composition produced at the Kuparuk CPF-2 facility during 2000 is presented below. Also shown below is a CPF-2 produced water analysis from February 2000. Maximum MI/lean gas and water injection rates into the Meltwater Oil Pool are estimated at 80 MMSCFPD and 65 MBWPD, respectively. There is no evidence from laboratory core flood experiments or compositional studies that indicate the fluids proffered for long-term injection would pose any appreciable compatibility problems for either the Meltwater Formation or its confining zones. Short periods of fresh water injection are also not expected to cause any appreciable compatibility problems. If injectors do incur damage from fresh water injection, remedial treatments (e.g., acid stimulations, high pressure breakdowns, etc.) can be employed. RECEiVED MAR 1 2 2001 .6,18s)(a Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 16/29 ) ) Miscible Injectant & Lean Gas Composition Supplied by the Kuparuk River Unit's CPF-2 Component MI Lean Gas (Mole 0/0) (Mole 0/0) CO2 0.89 0.5 N2 0.27 0.3 C1 81.37 69.6 C2 8.79 6.7 C3 5.10 5.0 i-C4 0.92 2.2 n-C4 1.99 6.3 i-C5 0.30 2.0 n-C5 0.28 2.5 C6 0.07 2.1 C7 0.01 1.8 C8+ 0.00 1.0 CPF-2 Produced Water Analysis Component Concentration (m all) 159 12 1,920 <0.15 20 35 18 137 13,131 <0.06 <10 12.6 0.74 1.2 <0.003 99 <0.5 60 20 8,800 6.7 Sulfate Sulfide Bicarbonate Aluminum Ammonia Barium Boron Calcium Chloride Chromium FI uoride Iodide Iron Lithium Manganese Magnesium Phosphorus Potassium Silicon Sodium Stronti um Meltwater Area Injection Order RECEI\/ED M/4R 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage Page 17/29 ') ) Meltwater Area Injection Order Attachment 10 20 AAC 25.402 (c)(10) Estimated Pressures The maximum MI and water injection pressures available at the plant will be 4,400 psi and 3000 psi, respectively. Due to pressure losses in the distribution system, actual maximum wellhead pressures will vary. Injection wells may also be choked to avoid exceeding injection targets. MI and water wellhead injection pressures are expected to range from 2,600 - 3,600 psi and 1600 - 2600 psi, respectively. RECEì\li:D MAR 1 2 2001 Alaska Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 18/29 ) J Meltwater Area Injection Order Attachment 11 20 AAC 25.402 (c)(11) Fracture Information Injection into the Meltwater Formation will not breach the reservoir's confining zones. Neither injection nor formation fluids will be able to enter any freshwater strata. Although bottom-hole pressures may exceed the formation parting pressure during enhanced recovery operations (i.e., water and MI injection), the Meltwater producing sands are separated by over 2000' of confining shales and mudstones which act as an impermeable barrier (see Attachment 11 A). These confining layers provide a substantially greater barrier than necessary to contain fractures within the Meltwater interval. Fracture modeling using Stimplan (i.e., Nolte/Smith's quasi 3-D model) confirms this as predicted fracture heights are entirely contained within the perforated interval. For example, injecting water at a rate of 10,000 BWPD at a surface pressure of 2200 psi would result in upward fracture growth of only 10'. Injecting MI at an injection rate 15 MMSCFPD at a surface pressure of 3500 psi would cause no appreciable height growth. The above-mentioned fracture modeling is based on single, planar, vertical fractures that result from relatively short duration injection. Since these modeling captures neither dentritic fractures nor disaggregation (i.e., destruction of the rock matrix), model predicted fracture growth associated with long term injection is too large. Hydraulically propped fracture stimulations are planned for Meltwater producers. The 1500' of confining shales and mudstones also provide a substantially greater barrier than necessary to contain these fracture stimulations. Fracture modeling using Stimplan suggests that typical fracture stimulations will grow upward approximately 100'. Model runs with worst case assumptions (which cause the most upward growth) suggest the stimulations will not exceed 300' of upward growth. For example, a fracture stimulation with 200,000 pounds of proppant with only 70' of gross interval is forecasted to result in a maximum upward fracture height of approximately 200' (see Attachment 11 B). As previously mentioned, no disposal injection is initially planned in the Meltwater Participating Area. However, the Ivishak sandstone is being permitted for Class II disposal to address potential future needs. Approximately 2000' tvd of confining rock separate this zone from Meltwater Reservoir strata. In addition, there are no potential fresh water strata within several thousand feet of the zone (see Attachment 11 C). If the Ivishak is used for disposal injection in the future, modeling will be conducted at that time using the best available tools to help ensure that the planned disposal volumes pose no risk to either potential freshwater strata or hydrocarbon recoveries. R E~-" t'-~ E' f\ I;: ¡<U~' \,J I V L-" MAR 1 2 2001 Meltwater Area Injection Order Alaska Oil & Gas COilS, Commission Anchorage Page 19/29 Attachment 11 A Meltwater North #2A Confining Intervals MELTWATER NORTH #2A GAMNA RAY í RESISTIVITY ~ ~i ~ :.:: ~ !.! D.. Lt5 ~~ :.:: ~ u ¡¡: 1..Y.tJo_.a~ , I D WI 111II ~AelTWATE.~ POOL Meltwater Area Injection Order Page 20/29 . . MAR 1 2 2001 Atta c h me nt 11 B ,;iéJSKa 8. Cèas Cons. Commission Anchoraqe Stimplan Results-Worst Case Height Growth - · . · . · . · . · . · . · . ... .......... .... ................. · ........ · .... · ...... ... .......... ... ........ · ........ : ::::~ : . : : : :~ :+....~. --:-...:...-:--...: (/) ... . ... . . . · . ... ... . ... ... . ... ... . ... · . ... . . . ... . . ... . ... ... . ... ... . ... .... ... .... . t ... .... ....... .. ..... ........ .......~.... .. ....... .. ....... .... ....... .... ..... · .. · .. · .. · .. · .. · .. · ... .... ............~... · .. · .. · .. · .. · .. · .. · .. · .. · .. · .. · . ... ... . ... :...:...::.. ...:r...: ~ ... .... ...c : :: :: (I) · .. .... ... .... .... ... ...... .... · .... .... · .... .. · . . . . . ....~...~.... .~...~ ... . ... ... . ... · . . . . . 5000 0 0 1ú 0 0 N ~ (f"J 0 D- o (l) '- ::J (f"J (f"J 0 (l) '- 1ú 0.. +-' (l) Z 0 N 0 5400 5800 Max Width 0.93 in phillips Alaska Inc. Meltwater Frac 2 At Closure 20 Meltwater Area Injection Order · · · · · · · ... . ... ... . ... ...................-.. · . ... . . . · . ... . . . · · · · · · · ... . ... ... . ....................................................... · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . .. . .................................................. · . . . . · . . . . · . . . . · . . . . · : Pad: : : : Area: : : · . . . · . . . · . .. .. ... ................................... · . . . · . . · . . : : :~ · . . · . . · . . · . . · . . .............................. .. · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . · . . . . ...ø.........~........ø.........~........ø........ · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . . · . . . .. · . . . . · . . . . ........ø.........~........~.........~........~...····. · . . . . · . . . . 5200 -- · · · · · · · · . ...... · . · . · . · . · . · . · . · · · · · · · · · · · · · · 5400 · · · ................ · · · Propped Area : · · · . .................... · . · · · · · · · o 5500 · · · · · · · · · . . . . . ....~..·~·..t·..t..1'·· 5700 · . .. . . . -0.E-0.4-0.;'0.0 0.2 OA 0.6 200 300 400 Fracture Penetration (ft) 500 100 . . · Io . . . . . . . . ........)...·......·;···..··,········,···········1····....I.~................)........;........;.......... . . . . . . . . . . · . . . . . 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Meltwater Area Injection Order Attachment 12 AAC 25.402 (c)(12) Formation Fluid No oil-water or gas-water contacts within the Meltwater formation have been encountered. In the Bermuda interval at Tarn, average salinity estimates from immobile connate water were estimated from low invasion cores. Connate water was obtained from core plugs using a miscible (CHCI3 / CH30H) extraction process. Subsequent water volumes were estimated using Karl Fisher analysis and chlorides were measured using ion chromatography. The resultant estimated connate water NaCI concentration was 30 Kppm. Anomalous lab results on Meltwater cores indicate a chloride content in the Bermuda Interval at Meltwater North of 20 Kppm NaC!. Due to uncertain lab procedures, Core Labs has little confidence in this value and estimates the actual value (based upon anion calculations) to be in the 35-40 Kppm NaCI range. Further testing on subsequent cored wells at Meltwater is planned. c MAR 1 2 200î Alaska Gas Cons, Meltwater Area Injection Order Page 23/29 . . RECE¡\lED Meltwater Area Injection Order Attachment 13 MAR 1 2 2DOí 20 AAC 25.402 (c)(13) Alaska Oil & Gas Cons. Commission Anchorage Aquifer Exemption The proposed Meltwater pool lies just south of the current Kuparuk River Unit (KRU) exemption area established by the EPA on May 11, 1984 (see Attachment 13A). An aquifer exemption is being sought for the Meltwater Pool, as there are no potential fresh water sands in the area suitable for human consumption. No porosity logs were acquired in the surface portion (above approximately 1900' tvd subsea) of the Meltwater North wells. As part of the permitting process for the exploration season, three wells with shallow logs were analyzed for water salinity (see below). Two of the wells (Kalubik #1 and Colville River St. 1) are outside the existing KRU and Alpine Aquifer Exemption Areas. The third well (Cirque 2) is located within the KRU Aquifer Exemption Area. The following table is a list of salinity calculations for the sand underneath the permafrost. Calculated fluid resistivities are corrected to 75° F and salinity numbers are in NaCI equivalent, or total dissolved solids (TDS). Rt = 2.1 Qm Rwa = 2.1 em (2.5 Kppm) SP = -20 mv (@ 35°) RwSP = 1.03 em (5.4 Kppm) a cu atlons are Inva I due to the presence of hydrates. Actual salinities are higher. SP more representative than Rwa, though still too low. In the Kalubik and Cirque wells, average resistivities drop dramatically below these sands, indicating much saltier waters. In the Colville well, the high salinities begin at the base of permafrost. Kalubik Water salinities below permafrost are estimated to be in the 10-12 Kppm range (TDS), increasing to 25 Kppm below 1950'. An analysis of a water sample from Albian aged sands (5050-5250') in this well tested 24.3 KPPM TDS. Meltwater Area Injection Order Page 24/29 . . Colville River St. 1 Salinities below permafrost are approximately 25 Kppm TOS. Cirque 2 Under permafrost, salinities are 6+ Kppm increasing to 21 Kppm below 2200'. The sand immediately below the permafrost is believed to contain gas hydrates. This causes log based salinity calculation results to be too low. Tarn 2N-349 In addition to the three wells above, Tarn Well 2N-349 was also analyzed for shallow water salinities. This well was logged across the shallow portion of the hole as part of a USGS study on gas hydrates. This well is located within the existing KRU Aquifer Exemption Area. The base of permafrost is 1310' at this location. Sands immediately below permafrost are affected by gas hydrates. This is supported by gas sampling done by USGS in Tarn Well 2N-305 (see Attachment 138). Calculated salinities below 1900' increase to 10 Kppm. R CEIVE[) MAR 1 2 2001 Aiaska Oii & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 25/29 AlpineAquifer Exemption hment 13A ional Aquifer Exemption Map Kuukpik Kalubik 1 It North S:ar Milne Point Kuparuk River Prudhoe Bay Alpine Pool Sections 2N-349 It Greater Kuparuk Aquifer Exemption 2 N2 Proposed Meltwater Pool Meltwater Area Injection Order Page 26/29 Attachment 138 rn 2N...305 Shallow Cuttings Samples ARN 2N 305 SH LLOW CD INGS GAS SAMP ES Gas Hydrates Area Injection Order Page 27/29 ) ) Meltwater Area Injection Order Attachment 14 20 AAC 25.402 (c)(14) Incremental Hvdrocarbon Recovery The Meltwater Sand was tested in the Meltwater #1 exploration well. Fluids recovered from the test indicated the interval contains 36° API gravity crude with a solution GOR of approximately 620 SCF/B. There is no evidence that this zone is in contact with either an aquifer or gas cap to provide pressure support. Simulation results indicate that an MW AG process with a cumulative 20% hydrocarbon pore volume slug of MI would provide an overall recovery factor of approximately 380/0 OOIP. This recovery factor is approximately 9% OOIP higher than that obtained from waterflood and more than 20% OOIP higher than that obtained from primary depletion. R t: ~~ E-' ~ \ / ;k: ~'-"~.~ \...J. ~ v C J,~J MAR 1 2 200î Alaska Oil & Gas Cons. Commission Anchorage Meltwater Area Injection Order Page 28/29 ') ) Meltwater Area Injection Order Attachment 15 20 AAC 25.402 (c)(15) Mechanical Condition of Existing Penetrations There are no active wells within a one-quarter mile radius of the Meltwater Oil Pool. However, two exploratory wells and a sidetrack were drilled to evaluate the area. These penetrations have been plugged and abandoned as per AOGCC regulations (20 AAC 25.112). All casing strings were cut three feet below the original ground level with well abandonment markers installed as per 20 AAC 25.120. The well cellars were removed and the remaining holes back filled to ground level with gravel. RECE~\/EC) MAR 1 2 In,! î¡ Alaska Oil & Gas COilS. Commission Anchorage Meltwater Area Injection Order Page 29/29 ) ) KUPARUK RIVER UNIT TESTIMONY FOR MELTWATER OIL POOL RULES , March 12, 2001 h ~ ~ PHILLIPS · PHilliPS Alaska, Inc. "lTlt A Subsidiary of PHILLIPS PETROLEUM COMPANY ~ . . ' ~..- I¡'"'"""'-' RECE\\¡ cU MAR 1 2 ZOOí 0'\ & Gas Cons, CommiSSion ,~\aska I Anchorage ) ') TABLE OF CONTENTS Paae I. Introduction 1 II. Geology 3 III. Reservoir Description 6 IV. Reservoir Development 9 V. Facilities 15 VI. Drilling & Well Design 18 VII. Reservoir Surveillance 24 VIII. Summary of Testimony 27 IX. Proposed Meltwater Oil Pool Rules 29 X. Proposed Findings & Conclusions 32 XI. List of Exhibits 34 V \.,.,- ?"-.~ RECE\' t.v Mp..R 1 2 2001 ,... cornmission . Oil & Gas 'vons, ,fl,\as\\a P"nchorage Meltwater Oil Pool Rule.... )estimOny ) March 12, 2001 I. Introduction This hearing has been scheduled in accordance with 20 MC 25.540 with a public notice period started on March 12. The purpose of this hearing is to present testimony to support classification of the Meltwater Reservoir in and around the Meltwater Participating Area as an oil pool and establish pool rules for development of said oil pool pursuant to 20 MC 25.520. Phillips Alaska, Inc. (PAl) is presenting testimony on behalf of the Meltwater Working Interest Owners (WIOs). The scope of this testimony includes a discussion of geological and reservoir properties, as they are currently understood, and PAl's plans for reservoir development and surveillance, well planning, facilities installation and project scheduling. This testimony will enable the Commission to establish rules that allow economical development of resources within the Meltwater Oil Pool. Confidential data and interpretation concerning the Meltwater formation will be furnished to the Commission as additional support testimony. Development drilling and facility installation are scheduled to commence during the second quarter of 2001 with initial production beginning by year-end. The proposed Meltwater Oil Pool includes all potential hydrocarbon-bearing zones within the Meltwater Reservoir. The areal extent of the pool is limited to areas that have been targeted for either development or possible exploratory activities. The WIOs recognize a need for a consistent development strategy for the Meltwater Reservoir. Pool rules for the entire reservoir will help maintain this consistency. As additional information and understanding of the Meltwater Reservoir is acquired, PAl will work with the Commission to ensure the Meltwater Oil Pool definition continues to make sense. Kuparuk River Unit (KRU) facilities will be employed to process production and supply injectant. The Meltwater Participating Area will be operated in accordance with special supplemental provisions to the Kuparuk River Unit Operating Agreement (i.e., the Meltwater Special Supplemental Provisions). The properties to be developed (i.e., the Meltwater Oil Pool) are leased from the State of Alaska. A portion of the Meltwater Oil Pool is located within the present boundaries of the Kuparuk River Unit. PAl, on behalf of the Meltwater Oil Pool WIOs, will be filing an application ("Unit Expansion Application") with the Commissioner of the Department of Natural Resources to expand the Kuparuk River Unit area to include the remainder of the Meltwater Oil Pool. The Unit Expansion Application will also request Department of Natural Resources approval of a Meltwater Participating Area, which will include the Meltwater Oil Pool. PAl intends to file this application no later than May 1, 2001. The Unit Expansion Application will also include plans of development and operations for 1 Meltwater Oil Pool Ru )-estimony ') ,I March 12, 2001 the Meltwater Participating Area, including the Meltwater Oil Pool. PAl will file a copy of the Unit Expansion Application with the Commission. The interests of the Meltwater WIOs will be integrated within the Meltwater Participating Area of the Kuparuk River Unit. Costs and production will be allocated in accordance with the Meltwater Special Supplemental Provisions. Ownership assignments have been filed with the Alaska Department of Natural Resources. The Meltwater Participating Area working interests are shown below. Phillips Alaska, Inc. BP Unocal Mobil Chevron 0.55957929 0.39754111 0.03960480 0.00218880 0.00108600 Total 1.00000000 2 Meltwater Oil Pool R, )Testimony ') March 12, 2001 II. Geology Introduction This portion of the testimony provides geologic data to the Commission in support of PAl's proposed Meltwater Oil Pool. Stratigraphic Nomenclature The Meltwater Reservoir is the sequence of reservoir sandstones and associated mudstones found in the interval between 4958' and 5368' tvd subsea in the Meltwater North #2A well, and in its lateral equivalents. The Meltwater Reservoir is late Cretaceous in age and stratigraphically within the Seabee Formation. The reservoir is approximately 400' thick and is composed of two intervals. The initial Meltwater Oil Pool includes the entire Meltwater Reservoir, however, the pool definition may change as additional information from development and exploratory activities becomes avai,!e:,ble. Both Meltwater Reservoir intervals are shown in the wireline log from the Meltwater North #2A well (Exhibit 1). Brief summaries of these intervals are given below in descending order. . The 'T4.1' or Cairn Interval was encountered between 4958' and 5187' tvd subsea in the Meltwater North #2A well. The boundaries are correlatable markers T4.1 and T3, respectively. Reservoir quality sands were not developed at this location, but may be present laterally. . The Bermuda Interval was encountered between 5187' and 5297' tvd subsea in the Meltwater North #2A well. The boundaries are correlatable markers T3 and T2, respectively. Hydrocarbon-bearing sands in this interval were encountered in the Meltwater North #2A and in two offset wells. Stratigraphic Description The Meltwater Sands comprise a sequence of oil-bearing, very fine- to fine- grained marine sandstones and interbedded mudstones. Initial injection operations will initially be restricted to these two intervals. As information is gained about the Cairn Interval, the Meltwater Oil Pool definition may be modified. The Bermuda interval is bounded by the T3 and T2 surfaces. The T2 surface appears to be erosional; the nature of the T3 surface is uncertain at this time. 3 Meltwater Oil Pool R~ )Testimony ') March 12,2001 Sand profiles vary from well to well. Sandbodies in the Bermuda interval consist of Channel fill and lobate deposits. The Cairn interval is bounded by the T3 and T4.1 surfaces. The T4.1 surface may be a conformable contact. The Cairn sandbody is linear in form. The areal distribution of Meltwater sandbodies is shown in Exhibit 2. Sandbodies are distributed in an overlapping geometry within the proposed Meltwater Oil Pool area. A{:Ie of Sediments Based upon Phillips in-house micropaleontologic and palynologic data, the Meltwater Sands sequence is late Cretaceous (Cenomanian-Turonian) in age. Proposed Pool Name The primary reservoir covered by this application was first encountered in 2000 in the Meltwater North #2 well. The use of II Meltwater" as the reservoir and pool names was based on the names of the confirmation wells (i.e., Meltwater North #1 and Meltwater North #2A). The zone was first flow tested during 2000 in the Meltwater North #1 well, where rates of approximately 4000 BOPD of 36 degree API oil were obtained. Proposed Vertical Pool Boundaries The Meltwater Oil Pool is the hydrocarbon accumulations in the sequence of oil- bearing, very fine- to fine-grained sandstones and mudstones between 4958' and 5368' tvd subsea in the Meltwater North #2A well and its lateral equivalents. This zone is bounded below by the T 4.1 log marker and above by the C35 log marker. C35 is recognized on Meltwater North #2A logs and its lateral equivalents as the low resistivity spike at 5368' tvd subsea representing the top of the Albian age shales underlying the Meltwater reservoir. T 4.1 is recognized by the high gamma-ray log reading above a blocky silty sand at 4958' tvd subsea in the Meltwater North #2A well and its lateral equivalents. Structure The Meltwater Oil Pool has been mapped using 3D seismic data. Structural dip is generally to the east. The T3 surface, the top of the Bermuda Interval, dips to the east-southeast; dipping approximately 2-3 degrees near the Meltwater North 4 Meltwater Oil Pool R,- )Testimony ) March 12, 2001 #1 well (Exhibit 3). Complex faulting is seen along the west (updip) edge of the Meltwater Oil Pool. Channel complexes positioned to the north, south and east of the Meltwater Oil Pool cut through the T3 reservoir and act as lateral boundaries. No faults are mapped within the main reservoir trends. Bermuda Interval depths range from approximately 4700' subsea in the west to 5500' subsea in the east. The Cairn Interval stratigraphically overlies the Bermuda Interval, and is offset to the east of the Bermuda Interval. The T4.1 surface, the top of the Cairn Interval, is shown in Exhibit 4. Faulting is similar to the pattern on T3. Structural depth of the Cairn Interval ranges from 4800' to 5500' subsea. Because of structural dip, the Cairn Interval is generally structurally level with or deeper than the Bermuda Interval Con trois on Oil Distribution Trapr>ing in the Bermuda and Cairn Intervals is stratigraphic, and hydrocarbon dis1ribution is controlled by sand distribution. No water or gas cap has been encountered within the Bermuda Interval. Both the Bermuda and the Cairn Intervals dip east with updip stratigraphic seals to the west. 5 Meltwater Oil Pool R ) Testimony ') March 12, 2001 III. RESERVOIR DESCRIPTION Introduction This section summarizes reservoir properties. Core data provides the foundation for much of the rock property information presented in this section. Whole cores were collected from the Meltwater North #1 and Meltwater North #2. In addition, rotary side-wall cores were obtained from the Meltwater North #2A and the Meltwater North #1 well (in a section where whole core was not obtained). A cased hole test of the Meltwater #1 provides the basis for the fluid information. Porosity, Permeability and Water Saturation The Meltwater Oil Pool sands are fine to very fine-grained and have common shale laminations and interbeds. Sands are compositionally heterogeneous. The major components are quartz, heterolithic rock fragments, plagioclase and zeolite. The heterolithic component consists of sedimentary, igneous and metamorphic rock fragments. Zeolites result from diagenetic alteration of volcanic glass. Dominant clays are chlorite, and Illite, with lesser amounts of kaolinite and 'stable-phasel mixed layer Illite/Smectite. While XRD analyses show clay content in the range of 15 to 25%, clay minerals are dominantly in the heterolithic grains rather than in the matrix. Core measured porosities range from 17% to 25% and average 20%). Corresponding air permeabilities range from 1 md to 80 md and average approximately 10 md. The average core based water saturation (after correcting for invasion) was measured at 40%. Net Pay Determination Petrographic observations were combined with laboratory analyses to determine the appropriate log model for the Meltwater Reservoir. A key observation is that the clay component within these rocks is dominantly located in framework grains, not the matrix. It was concluded that, despite the superficial appearance of the rocks, a shaley-sand log model was not appropriate. Instead, core porosity, which is total porosity, was matched with porosity logs, and then saturation was calculated using the standard Archie approach with laboratory-measured "m" and II n" values. Net pay is then determined by application of cut-offs on calculated total porosity and water saturation curves. The porosity cut-off is 170/0, based on a cross-plot of core porosity and permeability where 17% porosity equates to 1 millidarcy rock. A water saturation cut-off of 60% is used. 6 Meltwater Oil Pool RL ~h-estimony ) March 12, 2001 This value was determined by matching calculated net pay with pay counted from whole core. Reservoir Fluids and PVT Properties Reservoir fluid properties are estimated from fluids recovered during a cased- hole test of the Meltwater North #1 well. The well was on production for a total of 92 hours. At the end of the test, the well was éNeragi;¡g 3700 BOPD (of 36° API gravity crude) and 730 SCF/STB at a flowing tubing pressure of 380 psig. Original reservoir pressure of at the Meltwater #1 well was calculated at approximately 2400 psig from a pressure build-up test immediately following the flow test. Separator gas and separator liquid were physically in a high-pressure cell at reservoir temperature (135° F). After establishing thermal equilibrium, the contents were subjected to a constant mass expansion. Following the expansion, the contents were repressured and a differential vaporization was performed. Formation volume factor and viscosity values above bubble point were derived from the constant mass expansion whereas all other fluid properties were based on the differential vaporization. Results are summarized below. Pressure Bo Rs uo (psig) (Rvb/STB) (SCF/BO) ~ 3500 1.32 618 0.85 2500 1.33 618 0.76 2067 1.34 618 0.73 1800 1.31 550 0.75 1600 1.29 501 0.79 1400 1.27 452 0.86 1200 1.25 403 0.96 A corresponding compositional analysis is shown in Exhibit 5. 7 Meltwater Oil Pool ¡ '}s Testimony ) March 12,2001 Original Oil-in-Place Original oil-in-place (OOIP) is determined using volumetrics with expected reservoir parameters. Porosity and water saturation values are calculated from the Meltwater log model. The formation volume factor is based on results from the recombined fluid analysis performed on produced fluids from the Meltwater North #1 well test. Net pay and areal extent estimates are prepared from seismic maps (in which various seismic attributes are calibrated to the calculated net pay values for the existing penetrations). OOIP estimates were then chance weighted to account for gas and water fluid. The resultant Meltwater Sand OOIP estimates range from 50 to 200 MMBO, with an expected value of 125 MMBO. The chance-weighted OOIP estimate for the Cairn Sand in the vicinity of the Meltwater accumulation is 7 MMBO. 8 Meltwater Oil Pool R ) Testimony ') March 12. 2001 IV. Reservoir Development Introduction This portion of the testimony includes a discussion the recovery process selection and the development and management strategies that are planned to address uncertainties associated with the Meltwater Reservoir. Discussion is also presented 011 expected well performance. Recovery Process Selection One of the most critical aspects to the Meltwater development plan is the recovery process. Screening analysis resulted in a decision to initially pursue a recovery process involving altemating cycles of water and miscible gas (MWAG). Following are the main reasons for this selection: 1. Numerical simulation indicates that MWAG provides higher recoveries than any other competing recovery process (Le., primary drainage, waterflood, miscible gas flood, and lean gas flood). For example, simulation results suggest that an MWAG process, with a 200/0 cumulative hydrocarbon pore volume slug of injected miscible gas, would provide an incremental recovery of 9% OOIP compared to a waterflood process. This modeling work used stochastic reservoir descriptions (generated from geostatistical techniques) using Tarn analog data. 2. Enriched natural gas used at Kuparuk is miscible with Meltwater fluids at reservoir conditions. (Henceforth in this document, enriched natural gas will be referred to as "MI" for Miscible Injectant.) This is supported by slim tube simulation results (Exhibit 6) and is consistent with actual slim tube experiments run on Tam crude. (Given that the composition of Meltwater and Tam crudes are very similar, they should behave in a similar fashion from a phase behavior and fluid displacement standpoint. ) 3. GKA MI is currently piped to offset Tam Drill Site 2N and is transportable to Meltwater for a relatively small premium. 4. Initially pursing MWAG is imperative if this EOR process is to be employed. Meltwater's MI supply is dependent on existing west-end GKA infrastructure. The MWAG floods in this part of the GKA are relatively mature. Delaying implementation of MWAG at Meltwater would therefore jeopardize this project's EOR reserves, as critical GKA infrastructure may not be available in the future to transport MI. (Other potential uses of the GKA MI distribution system include de- bottlenecking productionlinjection lines and providing high pressure lift gas). 9 ì Meltwater Oil Pool R ) Testimony ) March 12, 2001 After the cumulative target slug size of MI has been injected into the formation, pressure support will be maintained with water injection. Current plans are to eventually inject lean gas into the reservoir to help recover light liquid hydrocarbons (used to manufacture MI) that will be trapped in the reservoir by the MWAG process. Recovery Mechanisms Initially employing an MWAG recovery process is integral to successfully developing the Meltwater Reservoir. HO~Never, given that the reservoir distribution is stratigraphically controlled with localized sand accumulations, some isolated areas may experience primary depletion. Although remedial measures (Le., additional drilling and well conversions) will be considered to help ensure pressure support is maintained, maintaining pressure support may not be justified in all situations. Development Approach The scope of the Meltwater development project involves drilling approximately 26 wells to develop 52 MMBO associated with the 132 MMBO OOIP estimate for the Bermuda Interval. (Reserve estimates include 2 MMBO from returned MI solvent and 3 MMBO from chance weighted exploratory targets.) The wells will be drilled from a single new drill site. Production would be initiated by yearend. Initial injection support would commence no later than six months after first production. Current plans are to develop the Meltwater accumulation primarily through a continuous development drilling approach (as opposed to phased development). However, in an effort to reduce risk, a phased drilling approach will be employed on a regional basis. Specifically, areas with questionable reservoir quality (e.g., poor continuity, low permeability, thin pay etc.) will be tested prior to initiating extensive offset development drilling activities. Well performance data and improved seismic calibrations acquired from the initial development wells would guide subsequent drilling plans. Exploratory drilling targeting the Cairn Interval will be conducted concurrently with Meltwater development drilling operations. Successful exploratory drilling results could alter existing plans by (1) changing the location and target interval of the initial development wells and (2) expanding the scope of the project to include additional wells. An expanded project scope may involve additional development drilling phases. An expanded project scope may also involve an areal and/or vertical expansion of the Meltwater Oil Pool definition. 10 " Meltwater Oil Pool Rl )Testimony ) March 12, 2001 Horizontal and/or high angle wells are planned in areas where a facies change is suspected. The purpose of these wells is to help ensure that adequate injection and withdrawal points are available. This will help optimize recovery in areas of potentially poor lateral continuity. Given the localized sand deposits associated with the Meltwater accumulation, a relatively high number of wells will likely be sidetracked compared with most other North Slope fields. The drilling order of the wells will therefore be optimized to test seismic anomalies along the periphery of the accumulation while maintaining safer "fallback" locations in the heart of the accumulation. Prior to spudding a well, sidetrack locations will be identified and included in the drilling application to help ensure that permitting issues do not interrupt drilling operations. Ongoing seismic interpretation will be a critical aspect when delineating the periphery. Relatively low risk well locations will be drilled near existing penetrations to provide time, when needed, for seismic reinterpretation. Optimization Optimizing field development will be an ongoing process requiring addi~ional field data and reservoir modeling. Work efforts currently planned to optimize total cumulative MI slug size and MI enrichment. For screening purposes, a cumulative MI slug size equal to 20% of the hydrocarbon pore volume (HCPV) was assumed. Optimizing slug size will require additional simulation work and integrating Kuparuk Large Scale EaR plans. Further work is also needed to determine the optimum enrichment level. Slim tube simulation results indicate that Kuparuk MI is richer than needed to achieve a miscible flood in the Meltwater Oil Pool. (A similar situation exists for the Tarn Oil Pool.) There remains a possibility that a specialized MI blend for the Meltwater Oil Pool may be employed (by adding produced gas to the Kuparuk MI stream). Plans are to develop the reservoir on nominally a 1 DO-acre well spacing. This spacing guideline was developed from an economic analysis, which took into consideration oil rate, cost and recovery impacts associated with various well spacings. Some portions of the reservoir, however, may require a relatively dense spacing to address permeability barriers (e.g., faults, mud drapes and calcite cement) or poorer than expected well (productivity/injectivity) performance. A 10-acre well spacing is therefore requested to allow a flexible well placement strategy that will maximize recovery. Unless optimization studies prove otherwise, plans are to are to inject approximately 20% HCPVI (46 BCF based on 132 MMBO) of Kuparuk MI. Reservoir pressure will be maintained to ensure that EaR reserves are not 11 Meltwater Oil Pooll\'~ T estímony March 12, 2001 compromised during the MWAG process. Well spacing will average close to 100 acres, although some areas may require a much closer spacing to optimize recovery. Well Conversion Strategy Since Meltwater Reservoir distribution is stratigraphically controlled and sand accumulations are. localized, sand continuity is expected to be difficult to predict. Producer/Injector interactions will therefore be difficult to predict in the absence of field data. De\lelopment plans call for minimizing the number of injection wells until producer/injector interactions are better understood. Producers will be converted to injection service as necessary in order to provide pressure support and minimize injection fluid cycling. Hence, to as large of an extent as possible, plans are to let reservoir performance be a guide in optimizing pattern configurations. Simulation work and Tarn analog data suggest that voidage can be maintained with MWAG at a producer/injector ratio of approximately two. Development plans are to therefore initially employ a producer/injector ratio of approximately two and adjust it as needed. As the flood matures (and more producers are converted to injection service), the producer/injector ratio is expected to decline to approximately one. Stimulation Plans The relatively tight nature of the Meltwater Reservoir coupled with vertical flow barriers makes producer propped hydraulic fracture stimulations desirable. Wellbore trajectories, cement and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Plans are to not initially stimulate injection wells. However, if injectivities are poor or if injection logs indicate significant portions of the reservoir are not accepting injectant, injectors will be stimulated with high-pressure breakdowns. An attempt will be made to minimize propped hydraulic fracture stimulations on injectors as this would complicate future profile modification efforts. Of course, injectors that were previously produced would have existing propped fractures in place. Secondary Targets The Bermuda Interval will be the primary target of initial development efforts. Current plans are to focus initial development efforts on that portion of the interval most likely have good reservoir characteristics. As previously shown on 12 Meltwater Oil Pool RL ITestimony ) March 12, 2001 Exhibit 1, potentially productive secondary targets in the Cairn Interval may be encountered during these development efforts. Secondary targets in the Cairn Interval are expected to generally be within 400' tvd of the Bermuda Interval. These thin, potentially productive zones contain insufficient reserves to merit separate wells or extensive completion design modifications. Although fracture stimulations are planned for Bermuda Interval producers, fracture modeling indicates these stimulations will only grow approximately 200' upwards. Potentially productive secondary pay zones can therefore only be developed if they can be inexpensively commingl~d with Bermuda production. Given the initial uncertainty of producer/injector interactions, most producers will be candidates for conversion to injection service. In order to maintain conversion flexibility, there are no casing design differences between production and injection wells. (Casing connections will be designed for gas or liquid service.) The flexibility to convert wells to injection service on an as needed basis is an integral part of the Meltwater development strategy. This complicates secondary target development as these targets can only be pursued if they are not isolated by more than one casing string. Pursing secondary targets may result in exceeding the AOGCC guideline that injectors provide annular isolation within 200' measured depth of the highest perforated interval. Plans are to provide annular isolation within 200' measured depth of the perforated zone, unless secondary targets are encountered with a pay thickness approaching or exceeding 10' tvd. Based on current drilling and facility hook-up plans, the productive nature of these secondary targets can not be fully ascertained during initial drilling operations. If future evaluations indicate that developing secondary targets can not be justified, there is the potential of having either initial or future injectors with annular isolation located more than 200 feet measured depth above the perforated zone. Help from the Commission is therefore needed to ensure that well service conversion flexibility is not sacrificed by attempting to pursue thin secondary targets. Well Peñormance There is considerable uncertainty in well performance projections. Similar to Tarn, large variations are expected in well productivities and injectivities. Meltwater development plans therefore require flexibility to address uncertainties and performance variations. Typically, Meltwater producers are expected to have initial average production rates in 2500 BOPO range. The average rate is expected to gradually decline during the first year of production before stabilizing at approximately 1500 SOPO/producer. 13 Meltwater Oil Pool R )Testimony ) March 12, 2001 Artificial Lift Most Meltwater producers not expected to initially require artificial lift due to a variety of factors; namely, the absence of produced water, relatively high initial GaRs (700 - 1500 SCF/B), light oil (360 API gravity crude), pressure support and the associated insitu gas lift resulting from MI breakthrough. Nevertheless, nodal calculations and Tarn analog data suggest that artificial lift will be needed on selective wells; specially, those that are located in low permeability areas or areas with tortuous injector-to-producer flow paths. Artificial lift will also be needed after water breakthrough occurs and water cuts begin to rise. Meltwater completions will include downhole jewelry that will allow the use of artificial lift, such as hydraulic jet pump, hydraulic piston pumps, lift gas, or plunger lift systems to be installed as needed. The completion design would allow hydraulic artificial lift systems to inject power fluid either down the tubing- casing annulus (with returned fluids flowing up the tubing) or vice-vers~a. Current hydraulic artificial lift plans are to inject power fluid down the annulus. Lean gas will not be initially available at Meltwater for lift purposes. Wells will 1)0 unloaded using either trucked nitrogen or locally available MI for lift gas. Wells requiring initial artificial lift will either use gas lift (with MI as lift gas) or jet pumps (with GKA injection water as power fluid). Artificial lift selection will be a well-by-well decision based on individual well properties and facility optimization. Low rate wells with paraffin deposition problems will likely involve jet pump lift as the warm injection water (-120° F) used for power fluid will prevent wellbore paraffin deposition. However, jet pump lift is not desirable for high rate wells. This is because high power fluid injection rates cause tubing hydraulic restrictions. (Typical power fluid/produced fluid ratios for Meltwater producers will be approximately two.) As Meltwater matures, gas lift will likely become the dominant artificial lift mechanism. After target MI slug volumes have been injected, the MI injection line will be available to carry lift gas from the GKA. The availability of a lean lift gas source will lower the opportunity cost associated with gas lift. (Using MI as a lift gas source has a relatively high opportunity cost as the light liquid hydrocarbons used to enrich the MI could otherwise be sold as oil.) As high rate wells experience water breakthrough and water cuts subsequently increase, artificial lift will be required on an increasing number of relatively high rate wells. As previously mentioned, gas lift is preferable to jet pump lift when lifting high rate wells due to tubing hydraulics. Other forms of artificial lift, such as electric submersible pumps, will also be considered as water production rates begin to rise. 14 Meltwater Oil Pool F\) Testimony ) March 12, 2001 v. Facilities Introduction This portion of the testimony summarizes the injectant sources that will initially be used at Meltwater. Discussion of the pads, roads, drill site facilities and other infrastructure is presented below. General Overview Meltwater production will be commingled with Tarn and Kuparuk production in surface facilities prior to final processing and ultimate custody transfer. Sharing existing production facilities is possible due to existing spare liquid capacity at Kuparuk's CPF-2 (central processing facility). Economical development is contingent upon utilization of these facilities. Meltwater will make maximum use of the existing Kuparuk River Unit (KRU) infrastructure. This maximizes reserves and minimiz.es the environmental impacts. The Meltwater Special Supplemental Provisions will govern the corresponding allocation of costs and production to the working interest owners. The miscible injectant employed at Meltwater will initially be the same injectant as that currently used in the Tarn and KRU Large Scale EOR Project. This injectant is manufactured at Kuparuk's CPF-1 and CPF-2 by blending lean gas from the KRU's production facilities with solvent (i.e., light hydrocarbon liquid streams) from the Prudhoe Bay Unit (PBU) and KRU. The light liquid hydrocarbons from the PBU are NGLs from the Central Gas Facility (CGF). The light liquid hydrocarbons from the KRU consist of scrubber liquids from artificial lift gas compression systems at CPF-1 and CPF-2, NGLs from CPF-1 and naphtha from the Topping Plant. After completing the MWAG recovery process, plans are to eventually inject lean gas into the Meltwater Oil Pool to maximize recovery of the light hydrocarbon liquids that were injected into the reservoir as part of the miscible injectant stream. The source of the lean gas will likely be Kuparuk River Unit's CPF-2. However, other potential gas sources will also be considered. (The average composition of CPF-2 MI and lean gas during 2000 is shown in Exhibit 7.) KRU CPF-2 oil processing is currently constrained by gas handling limits. The addition of Meltwater production will exacerbate existing facility limits. Efforts are currently planned to de-bottleneck CPF-2's gas handling constraints to help ensure Meltwater production has a minimal impact on KRU production. 15 Meltwater Oil Pool R )Testimony ) March 12,2001 Pads and Roads Meltwater development involves the addition of one new drill site to the Greater Kuparuk Area (GKA), Drill Site 2P, along with required ancillary and support facilities. Drill Site 2P will be just over ten miles south of existing Tarn Drill Site 2N. The drill site is designed to accommodate a total of 51 wells on 20-foot centers. A road connecting the new dlill site to the existing road system is routed from Drill Site 2N to Drill Site 2P. Four bridges are required along the roadway to cross small streams. Pipelines Cross-country pipelines include a 24-inch common line from Drill Site 2P to KRU 4-Corners, where it ties into the existing common line to CPF-2. The 24-inch line will also tie into 2N to help debottleneck Tarn surface line hydraulics. A new 12- inch water injection line will run from: KRU 4-Corners to 2P. The line will run through and be connected into Tarn Drill Sites 2L and 2N. Finally, an a-inch MI injection line will run from Drill Site 2N to Drill Site 2P. Pipelines are generally to be offset from g ravel roads by at least 450 feet. Related construction activities will be done from an ice road during winter 2000/2001. Powerlines Electrical power will be transmitted from Drill Site 2N to Drill Site 2P over new 34.5 kV power lines. The new transmission lines will be installed overhead. Drill Site Facilities The design premise for Meltwater facilities is for daily operations to require minimal operator presence. All data gathering and routine operations are to be accomplished remotely from CPF 2 and/or a Meltwater drill site control room. Data gathering is based on Moore Multi-Drop technology, which offers two wire control for all field instruments. Facilities to be installed initially at the drill site include: · Production, test, water injection and MI injection lateral piping and headers · Test separator for well testing · Test loop production heater · Instrumentation, control, and communication equipment. 16 Meltwater Oil Pool R ) Testimony ) March 12, 2001 Remote operations include: · Well testing using a conventional test separator · Emergency shutdown · Production choke control · Injection fluid metering and control · Gas lift and power fluid control · Production pressure metering · Annular pressure monitoring. Remote well control and testing functions will be performed using the Moore control system. Well production rate will be controlled using an automated choke valve. Testing can take place remotely through a divert valve system, which redirects the flow from the production header to the test. Emergency Shutdown Emergency shutdown systems meet API-RP-14C requireFl~nts and PAl specifications for safety systems. All production, test and water injection piping is designed to ANSI 1500 psi and will contain the wellhead shut-in pressure up to the pad emergency shut down (ESD) valves. The MI injection piping will be designed to ANSI 2500 psi in order to accommodate the injection pressures needed. (At an expected flowing tubing pressure of 1000 F, ANSI 1500 psi and ANSI 2500 psi provide working pressure ratings of approximately 3750 psi and 6250 psi, respectively.) Both production and injection wells can be shut in from over- and under-pressure through pressure switch signals which close the surface safety valves (SSVs). Individual wells can also be shut in remotely through the control system. The entire drill site can be shut in using the pad ESD valves. 17 Meltwater Oil Pool R ) Testimony ) March 12, 2001 VI. Drilling & Well Design Introduction The Testimony below discusses activities related to drilling and completing Meltwater Oil Pool wells. Discussion is also presented on safety systems, initial logging plans and completion design advantages. Ca=sfng & Cementing Casing and cementing plans for Meltwater wells are consistent with AOGCC Regulation 20 ACC 25.030. As in KRU wells, conductor casing will be set below 75 feet to provide anchorage and support for the rig diverter assembly. Surface casing size may be 9-5/8" or 7-5/8", depending on casing setting depth and produGtion tubing size. Surface casing will be set below the base of the West Sak interval, effectively casing off the permafrost, Ugnu, and West Sak formations. Meltwater wells utilize a tapered casing string tied back to surface, that serves as the combination production casing / tubing string installation. The casing adjacent from the producing interval is the same size as the tubing is at the surface (monobore). The casing across the production interval is then tied back to surface with a string of 3~" or 4~" tubing inserted into a seal bore or polished bore receptacle (positioned above the top pay zone perforation.) This provides a tubing annulus with isolation and pressure integrity (Exhibit 8). There are three casing programs proposed for the Meltwater development: Case 1) 31f2 inch Slim hole Monobore completions. This casing program utilizes a 7-5/8 inch (L-80, 29.7 pound) surface casing string with a production string of 5~ inch (L-80, 15.5 pound) casing crossed over to 3~ inch (L-80, 9.3 pound) casing across the Meltwater interval. These monobore wells will be completed with 3~ inch (L-80, 9.3 pound) production tubing. Case 2) 41f2 inch Monobore completions. This casing program employs 9- 5/8 inch (L-80, 40 pound) surface casing with 7 inch (L-80 or J-55, 26 pound) production casing crossed over to 4~ inch (L-80, 12.6 pound) production casing. 18 Meltwater Oil Pool R .) Testimony ) March 12,2001 Case 3) 3Y2 and 4Y2 inch Conventional completions. This casing program employs a string of 9-5/8 inch (L-80, 40.0 pound) casing and an intermediate 7 inch (L-80 or J-55, 26 pound) intermediate casing string set above the Meltwater formation top. A 3% inch (L-80, 9.3 pound) or 4 % inch (L-80, 12.6 pound) liner would then be set across the Meltwater formation and tied back to surface with either 3% inch (L-80, 9.3 pound) or 4% inch (L-80, 12.6 pound) production tubing. Each of these three well types may be completed for either production or injection service. The service of the well will be determined after logging operations. Drilling and cornpletion plans for future Meltwater wells may vary with time as experience and knowledge are gained. PAl proposes that the Meltwater casing and cementing rules be written as specified in 20 ACC 25.030 and in accordance with the current Kuparuk River Field rules as summarized below. 1) For proper anchorage and t:> divert an uncontrolled flow, a conductor casing shall be set at least 75 feet below the surface and sufficient cement will be pumped to fill the annulus behind the casing to surface. 2) For proper anchorage, to prevent an uncontrolled flow, and to protect the well from the effects of permafrost thaw-subsidence and freeze-back, a string of surface casing will be set at least 500 feet measured depth below the base of the permafrost section. Sufficient cement shall be pumped to fill the annulus behind the casing to surface (across the permafrost interval.) If the cement level in the annulus falls down-hole after the completion of the job, a top job will be performed. 3) The casing will be designed to withstand the maximum stresses imposed on it during the life of the well. Casing designs will employ the safety factors outlined below. Approved Casing Grades & Connections Tension design factor = 1.4 or higher Burst design factor = 1.0 or higher Collapse design factor = 1.0 or higher To prevent well failure due to permafrost action, the operator shall install surface casing including connections, with sufficient strength and flexibility to prevent failure. The surface casing, including connections, will have minimum post-yield strain properties of 0.90/0 in tension and 1.26% in compression. To be approved for use as surface casing, the Commission shall require evidence that the proposed casing and connections meet the above requirement. Several types and grades of casing, with connections, have been shown to meet the strain properties mentioned above, and have 19 Meltwater Oil Pool F ) Testimony ) March 12, 2001 previously been approved for use by the Commission (see partial list below). Other means for maintaining the integrity of the well from the effects of permafrost thaw-subsidence and freeze-back, based on sound engineering principles, may be approved by the Commission upon application. Approved Casing Grades & Connections 7 -5/B" 29.7 ppf LBO BTC 9-5/8" 36 ppf K55 BTC 9-5/B" 40 ppf K55 BTC 9-5/B" 47 ppf LBO BTe 4) Intermediate casing may not be required and that proposed Meltwater well designs Case 1 and Case 2 (utilizing conductor, surface and production casing) be allowed. However, intermediate casing may be used (Case 3) where either dictated by hole problems or in preparation to drill an over- pressured zone. 5) In addition to conventional cased and perforated completions, the following alternative completion methods: a) Open hole completions provided that the casing is $et not more than 200 feet above the uppermost oil bearing zone b) Slotted liners, wire-wrapped screen liners, or combination thereof, landed inside of cased or open hole - c) Horizontal completion with liners, slotted liners, wire-wrapped screens, or combination thereof, landed inside the horizontal extension or open hole d) Multi-lateral type completions in which more than one well bore penetration is completed in a single well, with production gathered and routed back to a central well bore. 6) The Commission may approve other completion methods upon application and presentation of data showing the alternatives are based on sound engineering principles. Although the standard program incorporates maintaining a tubing annulus with isolation and pressure integrity within 200' of the initial producing interval, as previously discussed, exceptions to this design criterion will be required to optimize recovery from potentially productive secondary targets. Blowout Prevention PAl proposes that the rule for blowout prevention in the Meltwater Oil Pool be written identically to the provisions established in Regulation 20 ACC 25.035 20 Meltwater Oil Pool R ) Testimony } March 12,2001 (Secondary Well Control: Blowout Prevention Equipment Requirements) of the AOGCC regulations. Except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance with API Recommended Practice 53 for blowout prevention systems. Drilling Fluids The drilling fluid program for Meltwater Wells will be prepared and implemented in full compliance with 20 AAC 25.033 in the AOGCC regulations. Good. engineering practices, offset well data and continuous monitoring of the mud system will be utilized to ensure well control during drilling operations. Formatiop pressure data for the strata to be penetrated is known and documented based on the three Meltwater reservoir penetrations during the exploration phase. Annular Disposal of DrillinQ Wastes Meltwater development will utilize the practice of annulus pumping of fluids incidental to well drilling activities. Fluids will be pumped down an adjacent annulus. Cuttings will either be ground and injected with the fluid, or separated and transported to a permitted disposal facility. Annulus pumping will be performed in accordance with 20 AAC 25.080. Fluids permitted for disposal include, but are not limited to: · Waste drilling fluids · Drill cuttings ground into slurry form · Excess rig washdown water · Excess cement returns from casing and cementing operations · Cement rinseate fluids generated from cementing operations incidental to drilling the wells · Cement contaminated drilling fluids · Completion fluids · Formation fluids · Reserve pit fluids · Drill rig domestic waste water · Other substances that the Commission determines are wastes associated with the drilling of a well. Disposal of such wastes in existing I or future, permitted North Slope Class II injection wells is also a possibility, and will be employed at operator discretion. 21 Meltwater Oil Pool F ) Testimony ') March 12, 2001 Wellhead and Production Tree Design Meltwater wellhead and production tree designs will be similar to those employed at Kuparuk. All wellhead and production tree equipment carries the API monogram and meets or exceeds API RP 14C. Directional Drilling MWD surveys will be used for directional drilling operations. Continuous MWD surveys have proven to be as reliable and accurate as gyro surveys on the North Slope and will be used as the definitive survey. TubinQ I Casing Annulus Mechanical Integrity Both proposed Meltwater injector and producing wells will have an annulus and seal bore I polished bore receptacle as part of their design, PAl will have the capability to pressure test the tubing I casing annulus to periodically verify the well's mechanical integrity. The casing testing method for Meltwater wells will comply with the requirements of 20 AAC 25.412 (c). Sufficient notice of pressure tests will be given so that a Commission representative may witness the test. Subsurface Safety Valves Consistent with statewide AOGCC regulations (20 MC 25.265) and current KRU Field Practice (as modified by Conservation Order 348), there is no apparent need for surface controlled sub-surface safety valves (SSSVs) in Meltwater wells. In keeping with Kuparuk guidelines, velocity sensitive subsurface valves (e.g., "K Valves") may be set wells with very high potential production rates. Surface Safety Valves Surface safety valves (SSVs) are included in the wellhead equipment. As previously mentioned, these devices can be activated by high and low pressure sensing equipment and are designed to isolate well fluids upstream of the SSV should pressure limits be exceeded. Testing of SSVs will be similar to the practice in Kuparuk formation producing wells. 22 Meltwater Oil Pool Rl )Testimony ) March 12,2001 Logging Operations The minimum log suite planned for Meltwater includes gamma ray and resistivity measurements obtained from the surface casing shoe to well TO. In addition, density and neutron logs may be utilized across this interval in selected wells. These logs will be obtained from MWO/LWO tools positioned in the drilling bottom-hole assembly. Well Design Profile modification and control of thief zones will be primarily managed by controlling fluid injection in offset injection wells. Profile modification in this reservoir management scenario is greatly facilitated by the monobore injector designs that allow mechanical patches to be run on wireline and selectively placed across discrete perforation sets. 23 Meltwater Oil Pool R ')Testimony ) March 12,2001 VII. Reservoir Surveillance Introduction This section provides testimony regarding reservoir surveillance and operations during production anomalies. Reservoir Pressure Measurements Pressures will be reported at a common datum of 5400' true vertical depth subsea. An initial pressure survey will be acquired for each well prior to establishing regular production or injection. On an annual basis, the minimum number of bottom-hole pressure measurements will be equal to the number of governmental sections included in the pool. PAl asks the Commission to giv(~ the operator more flexibility to collect pressure data in areas of special interest, as opposed to specified geographical areas based on governmental section. Allowable pressure survey techniques should include wireline RFT measurements, pressure buildups with bottom-hole pressure measurement, injector surface pressure falloffs, static bottom-hole pressure surveys following extended shut in periods, or bottom-hole pressures calculated from well head pressure and fluid level in the tubing of an injector which has been shut in a minimum of 48 hours. Pressure survey data would be reported to the Commission quarterly. Surveillance Logs Hydraulic propped fracture stimulations will limit the usefulness of production and injection logs. Surveillance logging will be used to monitor injection in wells that have not previously stimulated with hydraulic propped fracture stimulations. In addition, surveillance logs may also be employed when more than one zone is open in a single wellbore (e.g., wells with secondary targets). Fluid Samplinq Gas and/or liquid sampling will be periodically conducted during well tests during the miscible injection period of the flood. Compositional analyses will be performed on the samples to help gauge the effectiveness of the miscible flood. 24 Meltwater Oil Pool R ) Testimony ) March 12,2001 GOR Determination Gas-oil ratios (GaRs) will be routinely measured during well test operations. Despite concurrent production and injection, the relatively tight nature of the Meltwater reservoir coupled with a high solution gas content will cause primary depletion effects to increase initial gas production. This may cause GaRs to exceed limits set forth in 20 MC 25.240(b). Moreover, gas breakthrough from MI and/or lean gas injection will also cause GaR measurements to exceed these limits. An exception to 20 MC 25.240(b) is therefore requested. Production Allocation and Well Testing Reservoir management and surveillance requires accurate production data. A conventional test separator will be employed to help ensure these requirements are met. Liquid mass flow will be measured using a Micro Motion meter, water cut will be measured using a Phase Dynamics meter, and gas flow will be measured using orifice meters. The conventional test separator and associated meters are essentially the same test equipment employed at Kuparuk. One key difference, however, is that level controls will be placed on the liquid and gas legs of the Meltwater test separator. Test system pressure drop will ranges from 5 to 23 psi, with most wells closer to the 5 psi value. With a low back-pressure imposed by the metering equipment and a small flush volume (approximately 20 barrels), the time required to displace the previous well's fluids is short, minimizing stabilization time. Since low flow rate variance is anticipated, relatively short well tests should be operationally practical and accurate. Meltwater test equipment will also include a heater upstream of the separator to help ensure paraffin deposition does not interfere with well test accuracy. A test frequency of at least two well tests per month for each Meltwater producer is planned. Variance analyses techniques will be employed to identify wells that may benefit from a more frequent testing schedule. Additional testing will be conducted as needed to ensure that well tests accurately represent production rates. Hence, Meltwater producers will generally be tested more frequently than Kuparuk producers (which are required to be tested at least once per month). Although Meltwater well tests will occur more frequently than those at Kuparuk, the Meltwater tests will be included with Kuparuk wells tests and other satellites to determine overall allocation factors used for revenue and accounting purposes. However, the Satellite Produced Oil Allocation Factor, which will be applied to Meltwater, reverts to 1.00000 if the calculated GKA Produced Oil Allocation Factor exceeds 1.02000. Allocation factor calculations are detailed in Exhibit 9. 25 Meltwater Oil Pool R )Testimony ) March 12,2001 Production Anomalies Production prorations at or from Kuparuk facilities will affect all commingled reservoirs produced through the facilities by an equivalent percentage of oil production, unless this will result in either surface or subsurface equipment damage, or increased operating costs. One potential operating cost concern particular to Meltwater is paraffin deposition. A severe reduction in production through the Meltwater flow line could cause paraffin deposition if ambient temperatures are low. 26 Meltwater Oil Pool R )Testimony ) March 12,2001 VIII. Summary of Testimony The Meltwater working interest owners are first and foremost committed to a safe and environmentally sound operation. The proposed drilling program meets or exceeds all requirements specified in the Commission's rules and regulations. Meltwater facilities are designed to operate safely and efficiently. All well and facility designs meet or exceed the standards specified by state or national codes, the recommended practices of the relevant advisory organizations, and/or the time-proven practices of prudent operators. Plans are to make rnaximum use of the existing KRU infrastructure, thus minimizing environmental impacts while maximizing reserves for the Greater Kuparuk Area. Developing the Meltwater Oil Pool presents many challenges. The reservoir is relatively tight and injector/producer interactions are expected to be impeded by tortuous flow paths. The localized nature of the sand accumulations coupled with multiple Meltwater Reservoir horizons will complicate development efforts. Develop plans, which include ongoing seismic reinterpretation, 5idetrack planning, regionally phased development and minimizing the initial number of injectors until well interactions are better understood, should help addrE:ss these challenges. A key element of the development plan is initially employing a tertiary recovery process. Reservoir studies support using an MWAG process to maximize recovery. Delaying the tertiary recovery process would jeopardize Meltwater reserves as critical GKA MI distribution infrastructure may not be available in the future. The flood will be operated with the intent of exercising the majority of flood control at the injectors. To facilitate Meltwater Oil Pool development, exceptions to state wide regulations are requested for well spacing (MC 25.055{a}) and GaR production limits (MC 25.240{b}). Initial development plans call for 100 acre well spacing, however, 10 acre well spacing is requested to allow for flexibility in adjusting for reservoir heterogeneities (i.e., sand discontinuities, permeability barriers, etc.). No GaR production limits are requested because of plans to initially employ an MWAG recovery process. Maximizing recovery from the Meltwater Reservoir will require a collaborative effort between the Commission and the working interest owners. Pursuing potentially productive secondary pay zones within the reservoir may result in some injectors having annular isolation more than 200' above the top perforation. An ongoing reservoir surveillance program coupled with development drilling results and additional reservoir modeling studies will be used to help optimize the flood. As additional information is gained, fully developing this resource may involve an areal and/or vertical expansion of the Meltwater Oil Pool definition. 27 Meltwater Oil Pool R )TestimOny ) March 12,2001 Special emphasis has been placed on well testing because Meltwater production will be commingled with KRU production in surface facilities prior to final processing. A test system that operates as close to producing conditions as possible will be employed to ensure accurate well tests. A minimum of two well tests per month will be obtained. All volumes and tests will be summarized and reported to the Commission on a monthly basis. The development of the Meltwater resource is made possible through the sharing of the sxisting KRU infrastructure. PAl looks forward to working through the challenges of developing the Meltwater Oil Pool. Successfully developing this accumulation will provide additional infrastructure and insight that will be of value to other potential satellite development opportunities. Thank you for tt,e opportunity to present this testimony. 28 Meltwater Oil Pool RL}restimony ) March 12, 2001 IX. Proposed Meltwater Field Rules Rule 1. Field and Pool Name The field is the Kuparuk River Field and the pool is the Meltwater Oil Pool. Rule 2. Pool Definition The Meltwater Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between 5187' and 5297' tvd subsea in the Meltwater North #2A well Rule 3. Spacing Units Nominal spacing units within the pool wm be 10 acres. The pool shall not be opened in any well closer to 300 feet to an external boundary where ownership changes. Rule 4. Casing and Cementing Practices (a) Conductor casing will be set at least 75 feet below ground level and cemented to surface. (b) Where required for annular disposal, surface casing will be set at least 500 feet below the permafrost and be cemented to surface. Rule 5. Injection Well Completion (a) Wells may be employed for injection service provided a sealbore, packer, or other isolation device is positioned not over 200 feet above the top perforated interval. (b) Exceptions to Rule 5(a) will be permitted in cases where the distance between annular isolation and the top perforated zone exceeds 200 feet measured depth due to pursuit of secondary targets within the Meltwater Reservoir. 29 Meltwater Oil Pool RLJrestimony ) March 12, 2001 Rule 6. 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 7. Common Production Facilities and Surface Commingling (a) Production from the Meltwater Oil Pool may be commingled with production from the Kuparuk River Oil Pool and/or other oil pools in the KRU in surface facilities prior to custody transfer. (b) The allocation factor for the Meltwater Oil Pool will be equal to the Kuparuk allocation factor, except in cases where the Kuparuk oil all·)cation factor exceeds 1.05. Under these circumstances the Meltwater oil allocation factor will limited to 1.05. (c) Each producing Meltwater well will be tested a minimum of two times per month during the first year of regular production. (d) The operator shall submit monthly file(s) containing daily allocation data and daily test data for agency surveillance and evaluation. ' Rule 8. Reservoir Pressure MonitorinR (a) An initial pressure survey shall be taken in each well prior to establishing regular production or injection. (b) The minimum total number of bottom-hole pressure surveys measured annually will be equal to the number of producing or injecting governmental sections within the pool. Bottom-hole surveys as outlined in Rule 8(a) may fulfill the minimum requirement. (c) The reservoir pressure datum will be 5400' subsea. (d) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole formation tests. (e) Data and results from pressure surveys shall be reported quarterly on Form 10-412, Reservoir Pressure Report. (f) Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule. 30 Meltwater Oil Pool F ) Testimony ) March 12, 2001 Rule 9. Gas-Oil Ratio Exemption Wells producing from the Meltwater Oil Pool are exempt from the gas-oil ratio limit set forth in 20 MC 25.240(b). Rule 10. Pressure Maintenance Project Injection for pressure maintenance and enhanced oil recovery will commence within six months after the start of regular production from the Meltwater Oil Pool. Rule 11. 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: (a) Progress of enhanced recovery project(s) implementation and reservoir maqagement summary including engineering and geotechnical parameters. (b) Summary of produced and injected fluids by producing interval. (c) Summary of reservoir pressure analyses within the pool. (d) Results from any productionlinjection logs when more than one interval is commingled within a single wellbore. (e) Results of any special monitoring. (f) Future development plans. Rule 12. Production Anomalies In the event of oil production capacity proration at or from the Kuparuk facilities, all commingled reservoirs produced through the Kuparuk facilities will be prorated by an equivalent percentage of oil production, unless this will result in either surface or subsurface equipment damage, or increased operating costs. Rule 13. 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. 31 Meltwater Oil Pool Rl )restimony ) March 12,2001 x. Proposed Findings & Conclusions Phillips Alaska, Inc., as the Meltwater Oil Pool operator, respectfully proposes that the Commission make the following findings. 1. Initial development plans include approximately 26 wells, with approximately three fourth of the wells being drilled during 2001 and the remaining wells being drilled during 2002. 2. The total number of wells included in the project for full development will be better understood after initial development drilling and production/injection data help address some of the uncertainties associated with reservoir extent and sand continuity. 3. Pursuit of thin, potentially prodL:ctive secondary targets within the Meltwater Oil Pool may result in annular isolation occurring more than 200' measured depth above the top of the pertÖrated interval. 4. Injection into the Meltwater Oil Pool is scheduled to commence during late 2001 as facilities and wells associated with the project are brought on-line. 5. Meltwater development is dependent on GKA infrastructure. 6. Initially pursing an MWAG recovery mechanism at Meltwater helps ensure reserves are maximized. Delaying the implementation of this process jeopardizes EaR reserves, as critical GKA infrastructure may not be available in the future to transport MI to Meltwater. Recommended Conclusions Phillips Alaska, Inc., as the Meltwater Oil Pool operator, respectfully requests that the Commission make the following conclusions. 1. The Meltwater Development plan, which initially employs an MWAG process, involves the application of a tertiary enhanced oil recovery method in accordance with sound engineering principles. 2. The use of an MWAG process is reasonably expected to result in more than an insignificant increase in the amount of crude oil that ultimately will be recovered. 32 Meltwater Oil Pool Rl )Testimony ) March 12,2001 Requested Decisions Phillips Alaska, Inc., as the Meltwater Oil Pool operator, respectfully requests that the Commission endorse an initial MWAG process for field development. 33 ') Meltwater Oil Pool R )Testimony Exhibit 1 Exhibit 2 Exhibit 3 Exhibit 4 Exhibit 5 Exhibit 6 Exhibit 7 Exhibit 8 Exhibit 9 March 12, 2001 LIST OF EXHIBITS Type Section of the Meltwater Reservoir Meltwater Pool Area and Interval Trends Top of Bermuda (T3) Structure Map Top of Cairn (T4) Structure Map Crude Composition Analysis Meltwater Slim Tube Simulation Results Composition of CPF-2 MI & Lean Gas Meltwater Completion Designs Satellite Allocation Technique 34 EXHIBIT 1 Type Section of the Meltwater Reservoir MELTWATER NORTH 2A EXHIBIT 2 Meltwater Pool Area and Interval Trends EXHIBIT 3 Top of Bermuda (T3) Structure Map - - MELTWATER NORTH TOP BERMUDA (T3) DEPTH STRUCTURE MAP EXHIBIT 4 Top of Cairn (T4) Structure Map . . EXHIBIT 5 Crude Composition Analysis Sample: Primary Stage Separator Liquid from Meltwater North #1 Test Sampling Conditions: 150 psig & 85° F Analysis Method: Low Temperature Distillation / Programmed-Temperature, Capillary Chromatography ComDonent Hydrogen Sulfide Carbon Dioxide Nitrogen Methane Ethane Propane Iso-Butane n-Butane iso-Pentane n-Pentane Hexanes Heptanes Octanes Nonanes Decanes Undecanes Dodecanes Tridecanes Tetradecanes Pentadecanes Hexadecanes Heptadecanes Octadecanes Nonadecanes Eicosanes Heneicosanes Docosanes Tricosanes T etracosanes Pentacosanes Hexacosanes Heptacosanes Octacosanes Nonacosanes Triacontanes Hentriacontanes Dotriacontanes Tritriacontanes T etratriacontanes Pentatriacontanes Hexatriacontanes plus Mole % 0.00 0.02 0.00 3.65 2.10 5.77 1.68 5.29 2.12 3.88 8.52 5.81 9.17 6.22 5.34 4.17 3.57 3.59 3.01 2.77 2.10 1.94 1.93 1.66 1.41 1.22 1.17 1.06 0.97 0.93 0.80 0.69 0.66 0.63 0.57 0.52 0.42 0.43 0.37 0.30 3.54 Weiaht % 0.00 0.01 0.00 0.34 0.37 1.48 0.57 1.78 0.89 1.62 4.15 3.23 5.69 4.36 4.15 3.55 3.33 3.64 3.32 3.31 2.70 2.67 2.81 2.53 2.25 2.06 2.07 1.95 1.86 1.86 1.67 1.50 1.49 1.47 1.38 1.30 1.08 1.14 1.01 0.85 18.56 EXHIBIT 6 Meltwater Slim Tube Simulation Results :::- 95 c.. l- e"! ..... @ 90 >- ... (¡ > 0 (J (¡ 85 c: Õ Meltwater Slim Tube Simulation Results (Injection Fluid is Kuparuk MI - run at 1 100 n u ~ .. u .. 4Þ 80 2050 2100 2150 2200 2250 2300 2350 2400 2450 Slim Tube Operating Pressure . . EXHIBIT 7 Composition of Miscible Injectant & Lean Gas Supplied by the Kuparuk River Unit's CPF-2 Component MI Lean Gas (Mole %) (Mole %) CO2 0.89 0.5 N2 0.27 0.3 Cl 81.37 69.6 C2 8.79 6.7 C3 5.10 5.0 i-C4 0.92 2.2 n-C4 1.99 6.3 i-CS 0.30 2.0 n-Cs 0.28 2.5 C6 0.07 2.1 C7 0.01 1.8 CS+ 0.00 1.0 . . EXHIBIT 8 Meltwater Completions Designs FMC Prudhoe Gen V 9-518 x 5% x 3% 2.875" CAMCO OS nipple for Possible K-Valve 9-7/8" Hole 7-518" Surface Casing at 2,500' TVD 63,.(¡"Hole Baker CMU Sliding Sleeve wl2.813" OS Cameo profile Cameo 3W' x 1" side pocket GLM 5V2" Casing Sea] Receptacle (CSR) Crossed over to 3'1i' tubing at 5.000' TVD 3-112" Stirnhole Monobore Completion 3·1/2" or 4·112" Monobore Completion FMC Prudhoe Gen V 9-518 x 7 x 4% Base of pennafrost at 1,250' MD 1214" Hole Base of West Sak at 1,800' TVD 9·5/8" Surf. Csg. at 2,500' TVD JI/2" tubing 31/i' or 41/2" 81f2"Hole CAMCO 2.75" OS nipple 7" Casing Seal Receptacle (CSR) Crossed over to 4Vz" c"$ing at 5.000' TVD Production Casing at 5.200' TVD · , EXHIBIT 9 Satellite Allocation Technique General Allocation Factor = Actual Volume Theoretical Volume Produced Oil Allocation GKA Oil Allocation Factor = [CT Vol + KRUTP Diesel Vol- Load Diesel Vol- Exploration Vol + Delta Divert Tank Vol] [Kuparuk Well Test Oil Vol + Satellite Well Test Oil Vol] If GKA Produced Oil Allocation Factor < 1.02000, GKA Produced Oil Allocation Factor - = Satellite Produced Oil Allocation Factor = Kuparuk Produced Oil Allocation Factor If GKA Produced Oil Allocation Factor> 1.02000, Satellite Oil Allocation Factor = 1.00000 Kuparuk Produced Oil Allocation Factor = [CT Vol + KRUTP Diesel Vol - LoadDiesel Vol - Exploration Vol + Delta Divert Tank Vol - Satellite Well Test Oil Vol] + [Kuparuk Well Test Oil Vol] Produced Water Allocation GKA Produced Water Allocation Factor = Satellite Produced Water Allocation Factor = Kuparuk Produced Water Allocation Factor = GKA Injected Water Vol - Seawater Injected Vol (Kuparuk Well Test Water Vol + Satellite Well Test Water Vol) Produced Gas Allocation GKA Produced Gas Allocation Factor = Satellite Produced Gas Allocation Factor = Kuparuk Produced Gas Allocation Factor = GKA Injected Gas Vol + Kuparuk NGLs + Fuel + Flare (Kuparuk Well Test Gas Vol + Satellite Well Test Water Vol achment 1 A Net Pay Map with Planned Wells Meltw t r Bermu Interv I et Pay a F'L AN N ED PROOJCffi IIIIJEt.'f(JR INTERV AL '.'JELLS PRC!)I.JCffi IIIIJEC:1CR I NTE 11\1 AL WE LLS Meltwater Area Order 4/29