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Home My WebLink AboutAIO 018 . . INDEX AREA INJECTION ORDER 18 COLVILLE RIVER FIELD ALPINE POOL 1. September 3, 1999 2. September 13, 1999 3. September 16, 1999 4. October 5, 1999 5. October 19, 1999 6. October 19, 1999 7. November 05, 1999 8. November 16, 1999 9. November 18, 1999 10. January 04, 2000 11. January 10,2000 12. January 12,2000 13. January 12,2000 ARCO/AnadarkolUnion's Application AIO Affidavit of service to surface owners Notice of hearing, Bulk Mailing list, Affidavit Ltr from AOGCC to ARCO re: Application ARCOIAnadarko/Union's Application AIO Public Hearing Sign-in sheet Transcript of Proceedings Alpine Modification Email from EP A to AOGCC EP A-Alpine Permit Clarifications Email ARCO ltr requesting confidentiality Commissioner Oechsli request to participate Anadarko ltr of consent for CMR. Oechsli to participate ARCO ltr of consent for CMR. Oechsli to participate AIO 18 . . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive . Anchorage, Alaska 99501-3192 Re: The APPLICATION OF ARCO ALASKA, ) Inc. ("ARCO") for an order allowing an ) Enhanced oil recovery project in the Alpine ) Oil Pool, Colville River field, North Slope ) Alaska. ) Area Injection Order No. 18 Colville River Field Colville River Unit Alpine Oil Pool January 24, 2000 IT APPEARING THAT: 1. By application dated September 3, 1999, ARCO Alaska, Inc. ("ARCO") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to inject fluids on an area basis for the purposes of enhanced oil recovery from the Alpine Oil Pool. Additional information necessary to complete ARCO's application was submitted on September 13, 1999. 2. ARCO responded to additional questions and met with Commission staff on October 14, 1999 to discuss the Alpine Area Injection Order application. 3. Notice of opportunity for public hearing was published in the Anchorage Daily News on September 16, 1999. 4. A public hearing was held on October 19, 1999. FINDINGS: 1. Commission regulation 20 AAC 25.460 provides authority to issue an order governing underground injection of fluids on an area basis for all wells within the same field, faeility site, reservoir, project, or similar area. 2. The Alpine Oil Pool ("AOP") is located in the Colville River Delta area on Alaska's North Slope. 3. ARCO is the only operator of all wells within one-quarter mile of the area proposed for enhanced oil recovery. The State of Alaska and Kuukpik Corporation are the surface owners. 4. ARCO anticipates drilling approximately 112 development wells on 135 acre spacing to develop 429 million barrels of oil ("MMBO"). The estimated original oil in place ("OOIP") in the Alpine Oil Pool is 960 million barrels of oil. 5. Minimum values of formation water salinity in the Colville Delta Area, determined using standard openhole weIlbore geophysical methods calibrated to water samples collected from drill stem and production testing, range from 15,000 to 18,000 milligrams per liter ("mg/l") total dissolved solids ("TDS"). Area Injection Order No. 18 January 24, 2000 Page 2 . . 6. The Alpine Oil Pool is contained within the Alpine Sandstone, an Upper Jurassic aged, informal member of the Kingak Fonllation. It is the stratigraphically highest sandstone within the Kingak Formation in the Colville Delta area. The interval is approximately 7000 feet below sea level and net sand thickness ranges from 30 to 110 feet. 7. The Alpine Sandstone consists of very fine to fine-grained, moderate to well sorted, burrowed, quartzose sandstone with variable glauconite and clay content. Core porosity and permeability ranges are, respectively, from 15% to 23% and 1 to 160 millidarcies. Core area approximate average permeability ranges from 10-15 millidarcies and in the peripheral area 3-6 millidarcies. 8. Approximately 120 feet of ductile shale in the Miluveach Formation overlie the Alpine Sandstone. Core and log analyses indicate the parting pressure of the Miluveach shale is 600 to 700 pounds per square inch ("psi") greater than the Alpine Sandstone. 9. The Alpine Sandstone is underlain by approximately 150 feet of Upper Kingak Forn1ation shales. Petrophysical analysis indicates the parting pressure of the Kingak Formation shales is 700 to 800 psi greater than the Alpine sandstone. 10. Bottom-hole injection pressures are expected to exceed the Alpine formation parting pressure during normal operations. Rock mechanics and fracture analysis indicate that competent confining strata above and below the Alpine Sandstone will confine injected fluids within the Alpine formation. 11. Alpine Pool crude oil gravity is 40 degree API, solution gas-oil ratio is 850 scf/stb, bubble point is 2454 psig, and viscosity is .46 centipoise. Initial reservoir pressure is 3175 psig at 6864 feet TVDss (reference Conservation Order 443) and average reservoir temperature is 160 degrees F. 12. The Alpine crude oil properties create favorable reservoir water-oil mobility ratio that enhances areal and vertical waterflood sweep efficiency. Core flood studies showed residual oil saturation may be expected to range from 35-40% of the OOIP after a waterflood. 13. Estimated high residual water saturation after waterflood provided incentive to study the feasibility of a tertiary enhanced recovery process. 14. The miscible water-alternating-gas ("MWAG") project ARCO proposes is designed to start concurrent with initial pool production to avoid relative permeability related reduction of productivity and injectivity that is expected after "vater breakthrough. There is potential to prolong production of miscible oil to the extent it may severely impact economics and jeopardize miscible recovery. 15. Results of fine grid compositional reservoir simulations of a MW AG process initiated early in field life indicated ultimate recovery increased up to 10-12% OOIP or approximately 100 million barrels over waterflood. 16. Engineering data indicate productivity and injectivity of wells will be significantly reduced following injection water breakthrough at producing wells. The cause is combined effects of permeability; wettability and changes to relative permeability as alternating injected fluids displace reservoir fluids. 17. Simulations and reservoir properties indicated the strategy to maximize recovery was to place optimal volumes of miscible injectant ("MI") and water into the reservoir prior to injection watcr breakthrough at the producers. Area Injection Order No. 18 January 24, 2000 Page 3 . . 18. Laboratory experiments have demonstrated the recovery efficiency ofMI injection is a function of slug size and diminishes significantly for slug sizes exceeding 30% hydrocarbon pore volume. Optimal slug size is estimated to fall between 20-30%. 19. An equation of state calibrated to slimtube laboratory experiments was used to predict the amount of enriching material to blend with Alpine associated gas to achieve miscibility at a given pressure. 20. Modeling results indicate the proposed depletion plan will maintain the reservoir pressure within the Alpine Oil Pool at or above 3000 psi. 21. The MI slug volume injected will range between 20-30% of hydrocarbon pore volume. The MI will be manufactured from Alpine Pool associated gas and enriching liquids recovered from fuel gas to ensure a minimum miscibility pressure of 2,900 psi. 22. Beaufort Sea water, which has been tested and is compatible with the Alpine formation, will be used for injection initially. Produced water will be injected into the reservoir as it becomes available if it is compatible with the Alpine formation. 23. Produced fluids which are not compatible with the Alpine formation will be disposed in Colville River Unit Well WD-2 as described in Disposal Injection Order No. 18. 24. Production testing of wells in the Alpine Oil Pool has not yielded representative samples of Alpine Sandstone formation water. 25. Maximum MI injection pressures attainable at the plant discharge will be 4,500 psi. Maximum wellhead pressures will vary, and are expected to range from 3,600 to 4,300 psi. 26. Maximum water injection pump discharge pressure is expected to be 2,500 psi. Injection wellhead pressures may vary but are expected to be around 1,800 psi. 27. ARCO will demonstrate the mechanical integrity of injection wells as specified in 20 AAC 25.412 prior to initiating injection operations. 28. The operator will comply with the requirements of20 AAC 25.402 (d) & (e) to monitor tubing-casing annulus pressures of injection wells periodically during injection operations to ensure there is no leakage and that casing pressure remains less than 70% of minimum yield strength ofthe casing. 29. All existing wells drilled within the proposed prqject area have been constructed in accordance with 20 AAC 25.030. All wells abandoned in the proposed project area have been abandoned in accordance with 20 AAC 25.105 or an equivalent precursor regulation. CONCLUSIONS: 1. The application requirements of20 AAC 25.402 have been met. 2. An Arca Injcction Order is appropriatc for thc projcct area in accordance with 20 AAC 25.460. 3. No undcrground sources of drinking watcr ("USDW's") cxist bcncath the pcrmafrost in the Colville River Unit area. Area Injection Order No. 18 January 24, 2000 Page 4 e . 4. The proposed injection operations will be conducted in permeable strata, which reasonably can be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 5. Enhanced recovery injection fluids will consist of miscible gas and water implemented at startup in order to maximize ultimate recovery. 6. Ample confining shale exists above and below the Alpine Oil Pool to assure containment of the injected fluids within the Alpine formation. 7. The proposed Alpine tertiary enhanced oil recovery project is expected to result in a 10-12 % (approximately 100 million barrels) greater oil recovery than a waterflood project by itself. 8. Well mechanical integrity will be demonstrated in accordance with 20 AAC 25.412 prior to initiation of injection operations. 9. The mechanical integrity of each injection well will be tested at least every four years after an initial test. 10. Tubing-casing annulus pressure and injection rates will be monitored at least weekly for disclosure of possible abnormalities in operational conditions. II. An Area Injection Order covering the project area will not cause waste nor jeopardize correlative rights and will improve ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT Area Injection Order No. 18 is issued with the following rules governing Class II injection operations in the following affected area: UMIAT MERIDIAN TllN R4E Section 1,2,3,4,5, 7, 8, 9, 10, ll, 12, 13, 14, 15, 16,21,22,23,24,25,26,27. TllN R5E Sections 1,2,3,4,5,6,7,8,9,10, ll, 12, 13, 14, 15, 16, 17, 18, 19,20,21,22,23,24, 29, and 30. T12N R4E Sections 24, 25, 26, 27, 33,34,35 and 36. TI2N R5E Sections 13, 14, 15, 19,20,21,22,23,24,25,26,27,28,29,30,31,32,33,34,35 and 36. Rule I Authorized Injection Strata for Enhanced Recovery Within the affected area, fluids may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to and correlate with the interval between the measured depths of 6876 and 6976 feet in the Bcrgschrund No. 1 well. Rule 2 Fluid Injection 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 \-vell approved for conversion to a service well for injection in conformance with 20 AAC 25.280. Area Injection Order No. 18 January 24, 2000 Page 5 . . Rule 3 Monitoring the Tubing-Casing Annulus Pressure Variations The tubing-casing annulus pressure and injection rate of each injection well must be checked at least weekly to ensure there is no leakage and that it does not exceed a pressure that will subject the casing to a hoop stress greater than 70% of the casing's minimum yield strength. Rule 4 Reporting the Tubing-Casing Annulus Pressure Variations Tubing-casing ammlus pressure variations between consecutive observations need not be reported to the Commission unless well integrity failure is indicated as in Rule 6 below. Rule 5 Demonstration of Tubing-Casing Annulus Mechanical Integrity A schedule must be developed and coordinated with the Commission that ensures that the tubing-casing annulus for each injection well is pressure tested prior to initiating injection and at least once every four years thereafter. A test surface pressure of 1500 psi or 0.25 psi/ft. multiplied by the vertical depth of the packer, whichever is greater, will be used. The test pressure must show a stabilizing trend and must not decline more than 10% in a thirty-minute period. The Commission must be notified at least twenty-four (24) hours in advance to enable a representative to witness pressure tests. Rule 6 Well Integrity Failure Whenever operating pressure observations, injection rates, or pressure tests indicate pressure communication or leakage of any casing, tubing or packer, the operator must notify the Commission on the first working day following the observation, obtain Commission approval of a plan for corrective action, and obtain Commission approval to continue injection. Rule 7 Plugging and Abandonment ofInjection Wells An injection well located within the affected area must not be plugged or abandoned unless approved by the Commission in accordance with 20 AAC 25.105. Rule 8 Alpine Oil Pool Annual Reservoir Report An annual Alpine Oil Pool surveillance report will be required by April 1 of each year subsequent to commencement of enhanced oil recovery operations. The report shall include, but is not limited to, the following: a. Progress of the enhanced recovery project and reservoir management summary including engineering and geological parameters. b. Reservoir voidage balance by month of produced and injected fluids. c. Analysis of reservoir pressure surveys within the pool. d. Results and, where appropriate, analysis of production and injection log surveys, tracer surveys and observation well data or surveys. e. Results of any special monitoring. f. Reservoir surveillance plans for the next year. g. Future development plans. h. Review of Annual Plan of Operations and Development. Area Injection Order No. 18 January 24, 2000 Page 6 Rule 9 Administrative Action . . Upon request, the Commission may administratively amend any rule statcd above as long as the operator demonstrates to the Commission's satisfaction that sound engineering practices are maintained and the amendment will not result in an increased risk of fluid movement into a USDW. DONE at Anchorage, Alaska and dated January 24, 1999. Robert N. ristenson, P.E., Chairman Alaska Oil and Gas Conservation Commission ~~~J Camillé Oechsli Taylor, Commissione~ Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days ailer receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend. to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The CommIssion can refuse an application by not acting on it within the 10-day period. An atIected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day ailer the application for rehearing was filed) DRI t lf~cGraw Hill . ~andall Nòttingham 24 Hartwell Lexington, MA 02173 J - L15. PIRA ENERGY GROUP LIBRARY 3 PARK AVENUE (34th & PARK) NEW YORK, NY 10016 OVERSEAS SHIPHOLDING GRP ECON DEPT 1114 AV OF THE AMERICAS NEW YORK, NY 10036 NY PUBLIC LIBRARY DIV E GRAND CENTRAL STATION POBOX 2221 NEW YORK, NY 10163-2221 ALASKA OFC OF THE GOVERNOR JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON, DC 20001 OIL DAILY CAMP WALSH 1401 NEW YORK AV NW STE 500 WASHINGTON, DC 20005 ARENT FOX KINTNER PLOTKIN KAHN LIBRARY WASHINGTON SO BLDG 1050 CONNECTICUT AV NW WASHINGTON, DC 20036-5339 US MIN MGMT SERV CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON, VA 20170-4817 LIBRARY OF CONGRESS STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON, DC 20540 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON, DC 20585 ð+ (11 ,4· I L - C) /.A.f' (9g o I¿Dé:>j¿ tI TECt1ŠYS CORP BRANDY KERNS PO BOX 8485 GATHERSBURG, MD 20898 US GEOL SURV LIBRARY NATIONAL CTR MS 950 RESTON, VA 22092 DPC DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH, FL 32118 SD DEPT OF ENV & NA TRL RESOURCES OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY, SD 57702 AMOCO CORP 2002A LlBRARYIINFO CTR POBOX 87703 CHICAGO, IL 60680-0703 ILLINOIS STATE GEOL SURV LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN, IL 61820 LINDA HALL LIBRARY SERIALS DEPT 5109 CHERRY ST KANSAS CITY, MO 64110-2498 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA, KS 67202-1811 MURPHY E&P CO ROBERT F SAWYER POBOX 61780 NEW ORLEANS, LA 70161 UNIV OF ARKANSAS SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE, AR 72701 e e CRQSS TIMBERS ÒPERATIONS SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY, OK 73102-5605 DWIGHTS ENERGYDATA INC JERLENE A BRIGHT DIRECTOR PO BOX 26304 OKLAHOMA CITY, OK 73126 IOGCC POBOX 53127 OKLAHOMA CITY, OK 73152-3127 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO, OK 74055-4905 OIL & GAS JOURNAL LAURA BELL POBOX 1260 TULSA, OK 74101 BAPIRAJU 335 PINYON LN COPPELL, TX 75019 MARK S MALlNOWSKY 15973 VALLEY VW FORNEY, TX 75126-5852 US DEPT OF ENERGY ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS, TX 75201-6801 DEGOL YER & MACNAUGHTON MIDCONTINENT D,lVISION ONE ENERGY SO, STE 400 4925 GREENVILLE AVE DALLAS, TX 75206-4083 MOBIL OIL CORP MORRIS CRIM PO BOX 290 DALLAS, TX 75221 e e GAF,FNEY, CLINE I!. ASSOC., INC. ENERGY ADVISORS MARGARET ALLEN 16775 ADDISON RD, STE 400 DALLAS, TX 75248 GCA ENERGY ADV RICHARD N FLETCHER 16775 ADDISON RD STE 400 DALLAS, TX 75248 MOBIL OIL JAMES YOREK POBOX 650232 DALLAS, TX 75265-0232 JERRY SCHMIDT 4010 SILVERWOOD DR TYLER, TX 75701-9339 STANDARD AMERICAN OIL CO AL GRIFFITH POBOX 370 GRANBURY, TX 76048 CROSS TIMBERS OIL COMPANY MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH, TX 76102-6298 PRITCHARD & ABBOTT BOYCE B BOLTON PE RPA 4521 S. HULEN STE 100 FT WORTH, TX 76109-4948 SHELL WESTERN E&P INC K M ETZEL POBOX 576 HOUSTON, TX 77001-0574 ENERGY GRAPHICS MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON, TX 77002 H J GRUY ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON, TX 77002 e . 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ALASKA DIVISION ATTN: CORRY WOOLlNGTON POBOX 1635 HOUSTON, TX 77251 PETRINFO DAVID PHILLIPS POBOX 1702 HOUSTON, TX 77251-1702 PHILLIPS PETROLEUM COMPANY W ALLEN HUCKABAY PO BOX 1967 HOUSTON, TX 77251-1967 PHILLIPS PETR CO ALASKA LAND MGR POBOX 1967 HOUSTON, TX 77251-1967 WORLD OIL MARK TEEL ENGR ED POBOX 2608 HOUSTON, TX 77252 EXXON CO USA GARY M ROBERTS RM 3039 PO BOX 2180 HOUSTON, TX 77252-2180 EXXON CO USA M W ALBERS RM 1943 PO BOX 2180 HOUSTON, TX 77252-2180 EXXON CO USA J W KIKER ROOM 2086 POBOX 2180 HOUSTON, TX 77252-2180 e . EXXON CO USA RESERVES COORD RM 1967 POBOX 2180 HOUSTON, TX 77252-2180 e - PENNZOll E&P Will D MCCROCKLIN POBOX 2967 HOUSTON, TX 77252-2967 CHEVRON CHEM CO LIBRARY & INFO CTR PO BOX 2100 HOUSTON, TX 77252-9987 MARATHON Ms. Norma L. 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KURT SAL TSGAVER 1801 BROADWAY STE 1205 DENVER, CO 80202 JERRY HODGDEN GEOL 408 18TH ST GOLDEN, CO 80401 NRG ASSOC RICHARD NEHRING POBOX 1655 COLORADO SPRINGS, CO 80901-1655 RUBICON PETROLEUM, LLC BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS, CO 80906 e e JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE, ID 83702 RUI ANALYTICAL JERRY BERGOSH POBOX 58861 SALT LAKE CITY. UT 84158-0861 TAHOMA RESOURCES GARY PLAYER 1671 WEST 546 S CEDER CITY, UT 84720 MUNGER OIL INFOR SERV INC POBOX 45738 LOS ANGELES. CA 90045-0738 LA PUBLIC LIBRARY SERIALS DIV 630 W 5TH ST LOS ANGELES. CA 90071 US OIL & REFINERY CO TOM TREICHEL 2121 ROSECRANS AVE #2360 ES SEGUNCO. CA 90245-4709 BABSON & SHEPPARD JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH. CA 90808-0279 ANTONIO MADRID POBOX 94625 PASADENA, CA 91109 ORO NEGRO. INC. 9321 MELVIN AVE NORTHRIDGE, CA 91324-2410 PACIFIC WEST OIL DATA ROBERT E COLEBERD 15314 DEVONSHIRE ST STE D MISSION HILLS. CA 91345-2746 -; e 76 P.RODUCTS COMPANY èHARLES'BURRUSS RM 11-767 555 ANTON COSTA MESA, CA 92626 SANTA FE ENERGY RESOURCES INC EXPLOR DEPT 5201 TRUXTUN AV STE 100 BAKERSFIELD, CA 93309 TEXACO INC Portfolio Team Manager R W HILL POBOX 5197x Bakersfield, CA 93388 US GEOL SURV KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK, CA 94025 SHIELDS LIBRARY GOVT DOCS DEPT UNIV OF CALIF DAVIS, CA 95616 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE, CA 95969-5969 ECONOMIC INSIGHT INC SAM VAN VACTOR POBOX 683 PORTLAND, OR 97207 US EPA REGION 10 LAURIE MANN OW-130 1200 SIXTH AVE SEATTLE, WA 98101 MARPLES BUSINESS NEWSLETTER MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE, WA 98119-3960 DEPT OF REVENUE OIL & GAS AUDIT DENISE HAWES 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 e e GUI;SS & RUDD GEORGE LYLE 510 L ST, STE 700 ANCHORAGE, AK 99501 FAIRWEATHER E&P SERV INC JESSE MOHRBACHER 715 I ST #4 ANCHORAGE, AK 99501 DEPT OF REVENUE BEVERLY MARQUART 550 W 7TH A V STE 570 ANCHORAGE, AK 99501 DUSTY RHODES 229 WHITNEY RD ANCHORAGE, AK 99501 STATE PIPELINE OFFICE LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE, AK 99501 FORCENERGY INC. JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE, AK 99501 TRUSTEES FOR ALASKA 725 CHRISTENSEN DR STE 4 ANCHORAGE, AK 99501 YUKON PACIFIC CORP JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE, AK 99501-1930 PRESTON GATES ELLIS LLP LIBRARY 420 L ST STE 400 ANCHORAGE, AK 99501-1937 ALASKA DEPT OF LAW ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE, AK 99501-1994 e e GAF,O GREENPËACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE, AK 99501-2101 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS TIM RYHERD 550 W 7th AVE STE 800 ANCHORAGE, AK 99501-3510 DEPT OF REVENUE OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE, AK 99501-3540 N-I TUBULARS INC 3301 C Street Ste 209 ANCHORAGE, AK 99503 ANADARKO MARK HANLEY 3201 C STREET STE 603 ANCHORAGE, AK 99503 HDR ALASKA INC MARK DALTON 2525 C ST STE 305 ANCHORAGE, AK 99503 BAKER OIL TOOLS ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE, AK 99503 ALASKA OIL & GAS ASSOC JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE, AK 99503-2035 ANADRILL-SCHLUMBERGER 3940 ARCTIC BLVD #300 ANCHORAGE, AK 99503-5711 AK JOURNAL OF COMMERCE OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B Street Ste #210 ANCHORAGE, AK 99503-5911 e e DE~T OF NATURAL RESOURCES PUBLIC INFORMATION CTR 3601 C STREET STE 200 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 3601 CST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JULIE HOULE 3601 CST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OIL & GAS WILLIAM VAN DYKE 3601 CST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS BRUCE WEBB 3601 CST STE 1380 ANCHORAGE, AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JIM STOUFFER 3601 C STREET STE 1380 ANCHORAGE, AK 99503-5948 FINK ENVIRONMENTAL CONSULTING, INC. THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE, AK 99504-3305 ARLEN EHM GEOL CONSL TNT 2420 FOXHALL DR ANCHORAGE, AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE, AK 99504-4209 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507 e e STU HIRSH 9630 BASHER DR. ANCHORAGE, AK 99507 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC PETER J DITTON 6881 ABBOTT LOOP ROAD ANCHORAGE, AK 99507 RUSSELL DOUGLASS 6750 TESHLAR DR ANCHORAGE, AK 99507 US BLM AK DIST OFC RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE, AK 99507-2899 TRADING BAY ENERGY CORP PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE, AK 99508 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE, AK 99508 CASS ARlEY 3108 WENTWORTH ST ANCHORAGE, AK 99508 UNIVERSITY OF ALASKA ANCHORAGE INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE, AK 99508 US MIN MGMT SERV RICHARD PRENTKI 949 E 36TH AV ANCHORAGE, AK 99508-4302 US MIN MGMT SERV AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE, AK 99508-4302 e e us I)/IIN MGMT SERV RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS MINERALS MANAGEMENT SERVICE ALASKA OCS REGION 949 E 36TH A V STE 308 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV FRANK MILLER 949 E 36TH A V STE 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV LIBRARY 949 E 36TH AV RM 603 ANCHORAGE, AK 99508-4363 US MIN MGMT SERV RESOURCE EVAL JIM SCHERR 949 E 36TH A V RM 603 ANCHORAGE, AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE, AK 99508-4555 USGS - ALASKA SECTION LIBRARY 4200 UNIVERSITY DR ANCHORAGE, AK 99508-4667 CIRI LAND DEPT POBOX 93330 ANCHORAGE, AK 99509-3330 ANCHORAGE TIMES BERT TARRANT POBOX 100040 ANCHORAGE, AK 99510-0040 ARCO ALASKA INC MARK MAJOR ATO 1968 POBOX 100360 ANCHORAGE, AK 99510-0360 e e ARG,O ÁLASKA INc' SHELlA ANDREWS A TO 1130 PO BOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC SAM DENNIS ATO 1388 POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC LIBRARY POBOX 100360 ANCHORAGE, AK 99510-0360 ARCO ALASKA INC JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE, AK 99510-0360 PETROLEUM INFO CORP KRISTEN NELSON POBOX 102278 ANCHORAGE, AK 99510-2278 ARCO ALASKA INC KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE, AK 99510-6105 AL YESKA PIPELINE SERV CO PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE, AK 99512 e e AL YESKA PIPELINE SERV CO CHUCK áDONNELL 1835 S BRAGAW - MS 530B ANCHORAGE, AK 99512 AL YESKA PIPELINE SERV CO LEGAL DEPT 1835 S BRAGAW ANCHORAGE, AK 99512-0099 US BUREAU OF LAND MGMT OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE, AK 99513-7599 ANCHORAGE DAILY NEWS EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE, AK 99514 DAVID W. JOHNSTON 320 MARINER DR. ANCHORAGE, AK 99515 JWL ENGINEERING JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE, AK 99516-6510 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 ASRC CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE, AK 99518 e e , , BRI~TOL ENVIR SERVICES JiM MUNTER 201 E 56TH AVE STE 301 ANCHORAGE, AK 99518 e e ARMAND SPIELMAN 651 HI LANDER CIRCLE ANCHORAGE, AK 99518 HALLIBURTON ENERGY SERV MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE, AK 99518-2146 OPSTAD & ASSOC ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE, AK 99519 JACK 0 HAKKILA POBOX 190083 ANCHORAGE, AK 99519-0083 ENSTAR NATURAL GAS CO RICHARD F BARNES PRES POBOX 190288 ANCHORAGE, AK 99519-0288 MARATHON OIL CO BRAD PENN POBOX 196168 ANCHORAGE, AK 99519-6168 MARATHON OIL CO OPERATIONS SUPT POBOX 196168 ANCHORAGE, AK 99519-6168 UNOCAL KEVIN TABLER POBOX 196247 ANCHORAGE, AK 99519-6247 UNOCAL POBOX 196247 ANCHORAGE, AK 99519-6247 · . EX)ÇON COMPANY USA 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 INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC SUE MILLER POBOX 196612 M/S LR2-3 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE, AK 99519-6612 BP EXPLORATION (ALASKA) INC BOB WILKS MB 5-3 POBOX 196612 ANCHORAGE, AK 99519-6612 AMERICA/CANADIAN STRA TIGRPH CO RON BROCKWAY POBOX 242781 ANCHORAGE, AK 99524-2781 AMSINALLEE CO INC WILLIAM 0 VALLEE PRES PO BOX 243086 ANCHORAGE, AK 99524-3086 DIANA FLECK 18112 MEADOW CRK DR EAGLE RIVER, AK 99577 e e 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 PINNACLE STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER, AK 99577 DEPT OF NATURAL RESOURCES DGGS JOHN REEDER POBOX 772805 EAGLE RIVER, AK 99577-2805 COOK INLET KEEPER BOB SHAVELSON PO BOX 3269 HOMER, AK 99603 COOK INLET VIGIL JAMES RODERICK POBOX 916 HOMER, AK 99603 PHILLIPS PETR ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI, AK 99611 RON DOLCHOK POBOX 83 KENAI, AK 99611 DOCUMENT SERVICE CO JOHN PARKER POBOX 1468 KENAI, AK 99611-1468 KENAI PENINSULA BOROUGH ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI, AK 99611-3029 e e NANCY LÓRD PO BOX 558 HOMER, AK 99623 PENNY VADLA PO BOX 467 NINILCHIK, AK 99639 BELOWICH COAL CONSULTING MICHAEL A BELOWICH HC31 BOX 5157 WASILLA, AK 99654 PACE SHEILA DICKSON PO BOX 2018 SOLDOTNA, AK 99669 JAMES GIBBS POBOX 1597 SOLDOTNA, AK 99669 KENAI NATL WILDLIFE REFUGE REFUGE MGR POBOX 2139 SOLDOTNA, AK 99669-2139 VALDEZ PIONEER POBOX 367 VALDEZ, AK 99686 AL YESKA PIPELINE SERVICE CO VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ, AK 99686 VALDEZ VANGUARD EDITOR POBOX 98 VALDEZ, AK 99686-0098 UNIV OF ALASKA FAIRBANKS PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS, AK 99701 e e NkK STE'pOVICH 543 2ND AVE FAIRBANKS, AK 99701 RICK WAGNER POBOX 60868 FAIRBANKS, AK 99706 JACK HAKKILA POBOX 61604 FAIRBANKS, AK 99706-1604 FAIRBANKS DAILY NEWS-MINER KATE RIPLEY POBOX 70710 FAIRBANKS, AK 99707 C BURGLlN POBOX131 FAIRBANKS, AK 99707 FRED PRATT POBOX 72981 FAIRBANKS, AK 99707-2981 DEPT OF NATURAL RESOURCES DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS, AK 99709-4699 K&K RECYCL INC POBOX 58055 FAIRBANKS, AK 99711 ASRC BILL THOMAS POBOX 129 BARROW, AK 99723 RICHARD FINEBERG PO BOX416 ESTER, AK 99725 e e UNLV OF ALASKA FBX P~TR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS, AK 99775 e . UNIVERSITY OF ALASKA FBKS PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS, AK 99775-5880 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU, AK 99801-1182 DEPT OF ENVIRON CONSERV SPAR CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU, AK 99801-1795 SNEA(P) DISTR FRANCEIEUROPE DU SUD/AMERIQUE TOUR ELF CEDEX 45 992078 PARIS LA DEFENSE, FRANCE #13 ARCO Alaska, Inc. . Post Office Box 100360 Anchorage, Alaska 99510-0360 . J1d. ~~ ~". Mark M. Ireland Manager, Alpine Development Engineering 907-263-4767/ ANO-392 January 12, 2000 Mr. Robert N. Christenson, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Area Injection Order Alpine Oil Pool/Colville Field Dear Chairman Christenson: We have reviewed Commissioner Oechsli's January 10, 2000 memo regarding her participation in the Alpine Pool/Colville Field Area Injection Order decision. ARCO Alaska, Inc. has no objection to Commissioner Oeschli's participation in that decision. Very truly yours, J¿ Mark M. Ireland Manager, Alpine Development Engineering /keh ! ~ c- r t.;~ ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany #12 ANADARKO PETROLEUM CORPOR~ 17001 NORTHCHASE DRIVE . P.O. :.30 . TEL. (281) 875-1101 HOUSTON. TEXAS 77251-1330 January 12, 2000 Anada~~ Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3120 Attention: Mr. Robert N. Christenson Reference: Request to Participate in Area Injection Order Alpine Pool/Colville Field Ladies and Gentlemen: Anadarko Petroleum Corporation is in receipt of Memorandum dated January 10, 2000 to Robert N. Christenson from Cammy Oechsli requesting ARCO's and Anadarko Petroleum Corporation's consent to allow Cammy Oechsli to participate in the Area Injection Order Alpine Pool/Colville Field decision. Anadarko Petroleum Corporation has no objection to this request and hereby gives its consent as requested in the memorandum. Very truly yours, Anadarko Petroleum Corporation ~~Q' Craig A. Lewis Project Landman Cc: Cammy Oechsli-AOGCC Mark I reland-ARCO Alaska, Inc. Mike Erwin-ARCO Alaska, Inc. n E ...., F""f \/E [) 'p,é· ¡.~. ,5 ',. .' ","_ , . ~ J¡ ..'~ " ~ " .."01" ~""'"" ,4.,,;: ~ ,::IQ -1 :;. ~~4, #11 . . ME~10RANDUM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION TO: Robert N. Christenson Chair DATE: January 10,2000 FROM: Cammy Oechsli ~ . .. ..J Commissioner ~,.- \j SUBJECT: Request to Participate in Area Injection Order Alpine Pool/Colville Field ARCO Alaska, Inc. (" ARCO"), has a pending request for an Area Injection Order for the Alpine Oil Pool in the Colville River Field. A public hearing was held regarding this application on October 19, 1999. I was not present at that hearing. I wish to participate in the Area Injection Order decision and by copy of this memo am requesting the parties' consent to participate. I understand that any objection to my request by a party to the October 19 proceeding would automatically disqualify me from participating. My participation would be based on the condition that I had reviewed the entire record. I have had the opportunity to review the transcript of the hearing as well as the original application and subsequent documents submitted by ARCO concerning this application for Area Injection Order. By copy (and fax) of this memo I am requesting that ARCO and Anadarko Petroleum advise you whether they have any objection to my request to participate in this Area Injection Order decision by January 20,2000. cc: Mark Ireland - ARCO Alaska, Inc. Todd Liebel- Anadarko Petroleum #10 ARCO Alaska, Inc. . Legal Department Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 265-1354 Facsimile 907 265-6998 . ~~ ~~ Daniel G. Rodgers Senior Counsel January 4, 2000 Mr. Bob Christenson, Chairman Alaska Oil & Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Area Injection Order Alpine Oil Pool Colville River Unit REGEIVED Dear Chairman Christenson: JAN CA 2001 Alaska Oil & Gas Coos. Commission Anchorage At the October 19, 1999 hearing on ARCO's Application for the Alpine Injection Order, Fred Stalkup presented testimony in support of the Alpine Enriched Gas Miscible Project. During Mr. Stalkup's testimony, ARCO submitted for the record a document entitled "Petroleum Engineer's Certificate of Enhanced Oil Recovery Project" (Engineer's Certificate). At the hearing, ARCO requested that the Commission keep the Engineer's Certificate confidential. The purpose of this letter is to set forth the basis for ARCO's request for confidentiality. AS 31.05.035 and 20 AAC 25.537 provide that information voluntarily filed with the Commission will be kept confidential if the personal filing the information so requests. As stated above, at the October 19 hearing, ARCO requested that the Engineer's Certificate be kept confidential. Among other things, the Engineer's Certificate contains field cost information and oil production projections that are commercially sensitive, confidential and proprietary. This information derives independent and economic value from not being generally known to competitors who can obtain economic value from its disclosure or use. ARCO and Anadarko, the owners of the information, have made reasonable efforts to maintain the confidentiality of the Engineer's Certificate. Effective November 7, 1999, 20 AAC 25.540 was amended to include a new subparagraph (10) dealing with the disclosure of confidential information during hearings. Although the October 19 hearing on the Alpine Injection Order was ARea Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany January 4, 2000 Page 2 . . not governed by the revised 20 MC 25.540(10), ARCO's request for confidentiality satisfies the new requirements. Very truly yours, f1-:1 ß. c2~ Daniel G. Rodgers /keh cc: Commissioner Cammy Oechsli Commissioner Dave Johnston Gary Ford, Anadarko ARca Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany #9 EP A - Alpine Þ;::rât Clarifications , .¡ ~ Subject: EP A - Alpine Permit Clarifications Date: Thu, 18 Nov 1999 13:18:41 -1000 From: "Michael DErwin" <MERWIN@mail.aai.arco.com> To: blair _ wondzell@admin.state.ak.us, Wendy _ Mahan@admin.state.ak.us CC: "Mike A Stahl" <MST AHL@mail.aai.arco.com> Blair and Wendy, By now you have perhaps had time to review the draft permit modification sent out 11/16 by Grover Partee, Seattle EPA. I am writing to explain that what is presented is not in complete agreement with our original proposal, and represents a much more conservative and stringent surveillance approach than we anticipated. I would very much appreciate your opinions on this matter, feeling that you both represent a more experienced and seasoned approach to wellwork and surveillance methods. The history on this draft proposal is short. We have continued discussions with Grover and Jonathan over the past several months focusing on means of returning WD-02 to full injection capacity in spite of it's current packer location. We have reviewed several surveillance and mechanical means to provide casing isolation or enhance monitoring techniques, and discussed pros and cons of each. Grover has carefully and succintly documented the key options in his Fact Sheet. We are focusing in on increasing and enhancing surveillance methods to proactively monitor and evaluate casing condition to assure no fluids escape the casing. We feel this proactive approach is above and beyond the EPA surveillance methods, which focus on failure detection only. In this manner, we are prepared to take appropriate mitigating actions prior to casing failure, rather than after, even to the extent of moving the packer. But the draft permit revision is not specifically what we have asked for. There are several notable differences. 1. We did not request the changes be included in the permit. Future permit revisions are lengthy procedures, with comment periods, etc. We asked the permit be modified to allow for an "Enhanced Surveillance Program", with the specifics of that program included as an addendum. This addendum would then apply only to well WD-02, and would be outside the permit to facilitate future modifications as supported by surveillance data. What we see now does not include any such addendum. 2. The "Enhanced Surveillance" program we requested included several pieces; - annual caliper surveys, - pressure tests of the casing every 4 years unless caliper data recommended more frequent, - Arco would take appropriate remedial actions if any casing penetrations were detected in excess of 75% of the casing wall. The casing pressure test would be performed with inflatable wireline set bridge plugs set in the 7" casing above the perforations, then retrieved thru-tubing with slickline. This program is in addition to the baseline annual survey requirements, which include; - temperature surveys - radioactive tracer surveys - and annulus pressure testing. 3. The additional stipulation that injection will cease when a wall thickness penetration exceeding 50% is reached is unexpected and unnecessary. EPA testing is directed at failure detection, and short of failure, injection is allowed to proceed. Under this stipulation, we would be required to negotiate a solution well in advance of potential casing failure. In our proposal we tried to explain that our detection program would be proactive rather than reactive, yet this stipulation renders proactive surveillance punitive. 10f2 11/18/992:02 PM EP A - Alpine Pt:rúfit Clarifications , ., . 4. The wording in the current permit is directed at perforation depth, rather than the permitted injection zone. In this well, we are permitted for injection from the top of the Sag River to the base of the Sadlerochit. But we have only perforated the Sadlerochit interval. Placement of the packer based on perforations alone is short sided, and precludes future perforations that were approved in the permit process. The EPA has not yet given us a chance to comment on this draft as was originally agreed. It was our clear understanding that we would be able to review this in advance of other parties. This didn't happen, as our first viewing was concurrent with the e-mail notice you received as well. For that reason we have not formally drafted an initial reply to the EPA or discussed with them the reasoning behind the changes mentioned above. Mike Stahl and I would like very much to be able to review these changes with you in advance of our response to the EPA. Your experience and expertise in this matter as well is very much respected. If you have the time to discuss it with us it would be very much appreciated. Feel free to call at any time. Due to the hectic pace, I recommend my cell phone to avoid lengthy phone-tag (240-5817). I will be in touch as the week goes by. Mike 20f2 11118/99 2 :02 PM #8 Alpine Modification . ~ Subject: Alpine Modification Date: Tue, 16 Nov 1999 10:54:30 -0800 From: GROVER PARTEE <PARTEE.GROVER@epamail.epa.gov> To: blair _ wondzell@admin.state.ak.us, Wendy _ Mahan@admin.state.ak.us, BFristoe@envircon.state.ak.us, merwin@mail.arco.com, mstahl@mail.arco.com cc: WILLIAMS.JONA THAN@epamail.epa.gov I believe you all know already the reasons why this permit needs modification. Attached is alpmod.wpd, the current draft. I want to send this to Public Notice early in December or, if possible, even in November. Please look it over and provide me with any comments you have. The draft Fact Sheet (alpfs.wpd) is also attached If you can't read the attached WordPerfect files, let me know and I'll fax them to you. mm"<~'" "1- ¡ ~ f ~ALPFS.WPDI Name: ALPFS.WPD Type: WordPerfect Document (application/wordperfect5. Encoding: base64 Description: WordPerfect 6.0 Name: ALPMOD.WPD ~ ALPMOD.WPD T~pe: WordPerfect Document (application/wordperfect5.1) l.2j Encodmg: base64 Description: WordPerfect 6.0 ~~~m.u.,.mwm~·.·m.·.u"_·'·"_·_·--'->'·_'_~.""V"W'"~~M~'''."".m<y..·."...·o·o·___, 1 of! 11/18/9910:28 AM , . . FACT SHEET Proposed Modification of Underground Injection Control (UIC) Area Permit AK-1I003-A for the Construction and Operation of Class I Non-Hazardous Industrial Waste Injection Wells at the Alpine Oil and Gas Development of the Colville River Unit on the North Slope of Alaska U.S. Environmental Protection Agency, Region 10 Ground Water Protection Unit, OW-137 1200 Sixth Avenue Seattle, Washington 98101 November _,1999 Introduction ARCO Alaska, Inc. holds an Underground Injection Control (UIC) permit application for the construction and operation of up to three Class I non-hazardous industrial waste injection wells at the Alpine Field in the Colville River Unit on the North Slope of Alaska. The permit is effective until February 3,2009, and authorizes ARCO to inject all of the non-hazardous waste fluids generated at the Alpine Field into the naturally saline Ivishak and Sag River Formations at depths of about 8500 to 9500 feet below the land surface. Public Comment Peer review comments were sought from the Alaska Department of Environmental Conservation (ADEC) and the Alaska Oil and Gas Conservation Commission (AOGCC) in the development of the draft permit and this fact sheet. EP A is now requesting public comment prior to modifying the permit. Persons wishing to comment on the draft permit may do so in writing by December _, 1999. All comments should include the name, address, and telephone number of the person making comment, a concise statement of the exact basis of any comment, and the relevant facts upon which it is based. All written comments and requests should be submitted to EP A at the above address to the Manager of the Ground Water Protection Unit or via electronic mail to partee.grover@epa.gov After December _, 1999, EPA may finalize the modification as drafted if no substantive comments are received during the public notice period. Summary of Proposed Action and Permit Conditions The permit limits injection to the Ivishak and Sag River formations and requires injection be through tubing and a packer "installed in accordance with Appendix F of the permit application." That appendix indicated to EP A that the packer would be, at most, a few hundred feet above the injection interval. For a variety of reasons, ARCO installed the packer nearly 1100 feet above the injection interval. Thus, the Angency has been unwilling to authorize full operation of the facility. \ ~ . . EP A's concern, as set forth in letters dated April 30 and May 4, 1999, was that several hundred feet of casing below the packer would be exposed to injection pressures and the corrosive and erosive effects of the injectate. While underground sources of drinking water (USDWs) are not endangered by this situation - EPA has determined that there are no USDWs in the area - ARCO must still ensure that fluids are only injected into the authorized intervals. This includes routinely demonstrating the mechanical integrity of the pipe exposed between the packer and the perforations. At EP A's request, ARCO assessed several options including removing and repositioning the packer, extending the tailpipe, and significantly enhanced monitoring of the exposed casing. ARCO has requested and EP A proposes to approve the last of these options. Option 1: Repositioning the packer. This would require that the existing packer be drilled out and the tubing removed and reinstalled. This option would involve considerable time and expense. Also, there is some danger to the casing inherent in drilling out the packer at this depth. Option 2: Extending the tailpipe. If the tailpipe were extended, that portion of the annulus below the packer and above the bottom of the tailpipe could be filled with a lighter-than-water, noncorrosive fluid. However, standard mechanical integrity tests of the casing could still not be performed and access to the casing for other tests of corrosion and erosion would require removal of the tailpipe. ARCO was also very concerned that the tailpipe could easily fall into the hole during operations. A "lost" 600-800 feet of tailpipe would almost certainly crumple and the well would be rendered unusable. Option 3: Enhanced monitoring. This option more directly addresses the concerns raised by EP A at the outset yet avoids the significant expenses and risks involved in the other two options. ARCO will be required to annually perform a static pressure test and a caliper survey of the casing between 8550' TVD and 25' below the tubing tail. The top of the current perforations are at 8650' TVD. The packer is set at 7990' TVD and the tubing tail extends only about 70' belw the packer. Pressure testing will require setting a temporary packer. EP A contacts for further information are Grover Partee at (206) 553-6697 or Jonathan Williams at (206) 553-1369. It . . Page 1 of 16 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-11003-A In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated by the U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, ARCO Alaska, Inc. (permittee) is authorized to inject non-hazardous industrial waste through up to three Class I injection wells at the Colville Field of the Colville River Unit of the North Slope of Alaska, into the Ivishak and Sag River Formations, in accordance with conditions set forth herein. Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 USC 6901) or radioactive wastes are not authorized under this permit. Injection shall not commence until the operator has received written authorization from the EPA Director, Region 10 Office of Water, to inject. All references to Title 40 of the Code of Federal Regulations are to all regulations that are in effect on the date that this permit is issued. Appendices are referenced to the Alpine Development Project Underground Injection Control Permit application dated September 1997. This permit shall become effective on February 3, 1999, in accordance with 40 CFR 124.15. This permit and the authorization to inject shall expire at midnight, February 3, 2009, unless terminated. Signed this 3rd day of February, 1999 /s/ Randall F. Smith Randall F. Smith, Director Office of Water U.S. Environmental Protection Agency Region 10 This modification effective December _' 1999 Randall F. Smith, Director Office of Water U.S. Environmental Protection Agency Region 10 . . Page 2 of 16 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE .............................................................................................. 1 GENERAL PERMIT CONDITIONS ............................................................................................................. 4 EFFECT OF PERMIT ......................................................................................................................... 4 PERMIT ACTIONS....................................................................................................................... ....... 4 SEVERABILITY................................................................................................................... ................. 4 CONFIDENTIALITy...... ............... ........ ....................................... .................. ............... ......... .............. 5 GENERAL DUTIES AND REQUIREMENTS ...................................................................................... 5 Duty to Comply............................ ........ ............... ............ .......................................................... 5 Penalties for Violations of Permit Conditions ........................................................................... 5 Duty to Reapply....................................................................................................................... . 5 Need to Halt or Reduce Activity Not a Defense ........................................................................ 5 Duty to Mitigate...................................................................................................................... .... 5 Proper Operation and Maintenance ......................................................................................... 6 Duty to Provide Information. ...... ............. .......... .......... .............................................................. 6 I nspection and Entry................................................................................................................. 6 Records....................................................................................................................... .............. 6 Reporting Requirements........................ .................. ....... ................................... ...................... 8 Anticipated Noncompliance...................................................................................................... 8 Twenty-Four Hour Reporting....... ... .................................. ........... .............. ..... ...... .... ...... ... ....... 8 Other Noncom pliance ............................................................................................................... 8 Reporting Corrections............................................................................................................... 8 Signatory Requirements............................................................................................................ 8 PLUGGING AND ABANDONMENT ................................................................................................... 9 Notice of Plugging and Abandonment...................................................................................... 9 Plugging and Abandonment Report ....... ..... .... ....................... ..... ...... ... ....... ... ..... ..... ...... ... ........ 9 Cessation Limitation.................................................................................................................. 9 Cost Estimate for Plugging and Abandonment ....................................................................... 10 FI NANCIAL RESPONSI BI LlTY.......................................................................................................... 10 WELL SPECIFIC CONDITIONS................................................................................................................. 11 CONSTRUCTION.................................................................................................................. ............ 11 Casing and Cementing ............................ ..... .... ......... .............. ....... .... ..... ..... ... .......... ... ........ ... 11 . . Page 3 of 16 Tubing and Packer Specifications......... ........ ............ ............ ....... ......... ..... ............ .... ..... ... ..... .11 New Wells in the Area of Review .............................................................................................11 CORRECTIVE ACTION..................................................................................................................... 11 WELL OPERATION........ ............. ........ ................... .............. ........ .................. ................................... 11 Prior to Commencing Injection ................................................................................................ 11 Mechanical Integrity ........... ........ ......................................... .............................. ...................... .12 Injection Intervals.............................................................. ......... ............................................. 13 Injection Pressure and Rate Limitations................................. .................. ..... ................ .......... 13 Annulus Pressure ................ ........ ...... .... ............................. ......... ... ........... ..... ....... ... ...... ......... 13 Injection Fluid Limitation..... ..... .............. ..................................... ..... ........... ..... ........................ 13 MONITORING.................................................................................................................... ................ 14 Monitoring Requirements........................................................................................................ 14 Continuous Monitoring Devices............................................................................................... 14 Alarms and Operational Modifications .................................................................................... 14 REPORTING REQUIREMENTS................ ................................................................... ..................... 14 Quarterly Reports.................................................................................................................... 14 Report Certification.................................................................................................................. 14 REPORTING FORMS ................. ......... ............... .................... .......... ............................................ ............. 16 . . Page 4 of 16 . . Page 5 of 16 PART I GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The underground injection activity, otherwise authorized by this permit, shall not allow the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR Part 141 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act (SDWA). Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other law governing protection of public health or the environment from imminent and substantial endangerment to human health or the environment. This permit may be modified, revoked and reissued, or terminated during its term for cause. Issuance of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. This permit is based on the permit application submitted in September 1997. B. PERMIT ACTIONS 1. Modification, Reissuance or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 CFR 144.39 and 144.40. Also, the permit can undergo minor modifications for cause as specified in 40 CFR 144.41. The filing of a request for a permit modification, revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance on the part of the permittee does not stay the applicability or enforceability of any permit condition. 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 CFR 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the permittee and incorporate such other requirements as may be necessary under the SDWA. C. SEVERABILITY The provisions of this permit are severable, and if any provision of this permit or the application of any provision of this permit to any circumstance is held invalid, the application of such provision to other circumstances, and the remainder of this permit, shall not be affected thereby. D. CONFIDENTIALITY In accordance with 40 CFR Part 2, any information submitted to EPA pursuant to this permit may be . . Page 6 of 16 claimed as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 CFR 2.203 and on the application form or instructions, or, in the case of other submissions, by stamping the words "confidential" or "confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 CFR Part 2 (Public Information). Claims of confidentiality for the following information will be denied: 1. The name and address of the permittee. 2. Information which deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS 1. Duty to Comply The permittee shall comply with all conditions of this permit. Any permit noncompliance constitutes a violation of the SDWA and is grounds for enforcement action, permit termination, revocation and reissuance, modification, or for denial of a permit renewal application; except that the permittee need not comply with the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR 144.34. 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty not to exceed $27,500 per day of such violation. Any person who willfully or negligently violates permit conditions is subject to a fine of not more than $27,500 per day of violation and/or being imprisoned for not more than three (3) years. 3. Duty to Reapply If the permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Halt or Reduce Activity Not a Defense It shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to MitiQate The permittee shall take all reasonable steps to minimize or correct any adverse impact on the environment resulting from noncompliance with this permit. 6. Proper Operation and Maintenance The permittee shall, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance . . Page 7 of 16 includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. 7. Dutv to Provide Information The permittee shall provide to the Director, within a reasonable time, any information which the Director may request to determine whether cause exists for modifying, revoking and reissuing, or terminating this permit, or to determine compliance with this permit. The permittee shall also provide to the Director, upon request, copies of records required to be kept by this permit. 8. Inspection and Entry The permittee shall allow the Director, or an authorized representative, upon the presentation of credentials and other documents as may be required by law to: a. Enter upon the permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records that are kept under the conditions of this permit; c. Inspect at reasonable times any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit; and d. Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any contaminants or parameters at any location. 9. Records a. The permittee shall retain records and all monitoring information, including all calibration and maintenance records and all original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of all data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. These periods may be extended by request of the Director at any time. b. The permittee shall retain records concerning the nature and composition of all injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the permittee shall deliver the records to the Director. The permittee shall continue to retain the records after the three year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; (2) The name(s) of the individual(s) who performed the sampling or measurements; (3) The date(s) analyses were performed; . . Page 8 of 16 (4) The name(s) of the individual(s) who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 CFR 136.3 or in appendix III of 40 CFR Part 261 or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including, but not limited to measurements of pressure, temperature, mechanical integrity, and chemical analyses shall be done in accordance with EPA's Quality Assurance Program Plan. f. As part of the COMPLETION REPORT, the operator must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; (2) The test methods that will be used to test for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. Where applicable, the Waste Analysis Plan (WAP) from the permit application may be incorporated by reference. g. The permittee shall complete a written manifest for each load of waste received. The manifest shall contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results, a statement stating if the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4, and any information on extraordinary occurrences. For waste streams piped more or less continuously from the source(s) to the wellhead, the permittee shall provide for continuous, recorded measurement of the discharge volume and shall provide such sampling and testing as may be necessary to provide a description of the nature and composition of all injected fluids, and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4 h. Dates of most recent calibration or maintenance of gauges and meters used for monitoring required by this permit shall be noted on the gauge or meter. 10. Reporting Requirements The permittee shall give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected fluid. . . Page 9 of 16 11. Anticipated Noncompliance The permittee shall give advance notice to the Director of any planned changes in the permitted facility or activity which may result in noncompliance with permit requirements. 12. Twenty-Four Hour Reportinq a. The permittee shall report to the Director any noncompliance which may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the permittee becomes aware of the circumstances. The following shall be included as information which must be reported orally within 24 hours: (1) Any monitoring or other information which indicates that any contaminant may cause an endangerment to an underground source of drinking water. (2) Any noncompliance with a permit condition or malfunction of the injection system. b. A written submission shall also be provided within five (5) days of the time the permittee becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause, the period of noncompliance, including exact date and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue, and steps taken or planned to reduce, eliminate, and prevent recurrence of the noncompliance. 13. Other Noncompliance The permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted. The reports shall contain the information listed in Permit Condition E-12.b. 14. ReportinQ Corrections When the permittee becomes aware that he failed to submit any relevant facts in the permit application or submitted incorrect information in a permit application or in any report to the Director, the permittee shall promptly submit such facts or information. 15. SiQnatorv Requirements a. All permit applications, reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level of vice-president, or by a duly authorized representative of that person. A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. . . Page 10 of 16 (3) The written authorization is submitted to the Director. b. If an authorization under paragraph a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph a. of this section must be submitted to the Director prior to or together with any reports, information or applications to be signed by an authorized representative. c. Any person signing a document under paragraph a. of this section shall make the following certification: "I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F. PLUGGING AND ABANDONMENT 1. Notice of PluQginQ and Abandonment The permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2. PluQginQ and Abandonment Report The permittee shall plug and abandon the well as provided in the PLUGGING AND ABANDONMENT PLAN (Appendix F), which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the permittee shall submit a report to the Director in accordance with 40 CFR 144.51 (p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the permittee shall plug and abandon the well in accordance with the plan unless he: a. Provides notice to the Director; b. Demonstrates that the well will be used in the future; or c. Describes actions or procedures, satisfactory to the Director, that the permittee will take to ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the technical requirements applicable to active injection wells unless waived by the Director. 4. Cost Estimate for PluQQinQ and Abandonment a. The permittee estimates the 1997 cost of plugging and abandonment of the permitted wells . . Page 11 of 16 to be $1,000,000 each b. The permittee must submit financial assurance and a revised estimate in April of each year. The estimate shall be made in accord with 40 CFR 144.62. c. The permittee must keep at the facility during the operating life of the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes, the documentation submitted under 40 CFR 144.63(f) shall be amended as well to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. e. The permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. G. FINANCIAL RESPONSIBILITY The permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close, plug, and abandon the underground injection well. If the financial test and corporate guarantee provided under 40 CFR 144.63(f) should change, the permittee shall immediately notify the Director. The permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that alternative demonstration to the Director and the Director notifies him that the alternative demonstration of financial responsibility is acceptable. . . Page 12 of 16 PART /I WELL SPECIFIC CONDITIONS A. CONSTRUCTION 1. Casing, CementinQ and LOQQinq The permittee shall case and cement the well(s) to prevent the movement of fluids into strata other than the authorized injection interval (see II.C.3, below). Casing and cement shall be installed in accordance with application Appendix F. The permittee shall, at a minimum, run the open- and cased·hole logs as described in application Appendix F. The permittee shall provide not less than ten days advance notice to the Director of all cementing operations. 2. Tubing and Packer Specifications The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with Appendix F of the permit application. Except as may otherwise be authorized herein, the packer shall be located not more than 100 feet uphole from the uppermost perforations. With respect to WD-2 completed in April 1999 with the packer as installed at approximately 7865 feet TVD, operation is authorized provided the following criteria are met. Not later that April 1, 2000, and not less often than annually thereafter: (a) The permitee shall install a temporary packer not more than 50 feet uphole from the current perforations and shall pressure test, as described for the tubing-casing annulus in Part /I C.1 (b), below, the casing between the temporary packer and the permanent packer; and (b) The permitee shall perform a caliper survey, with a tool utilizing not less than 15 feelers, of the casing beginning not more than 50 feet above the current perforations and extending upward to not more than 25 feet below the bottom of the tailpipe. In the event that the casing fails to hold pressure, as defined in Part II.C.1 (b), or the caliper survey indicates a loss of more than 50% of wall thickness in any part of any joint, operation of the well shall cease until resumption is specifically authorized by EPA. 3. New Wells in the Area of Review This page modified effective December _' 1999 . . Page 13 of 16 New wells within the area of review shall be constructed in accordance with the Alaska Oil and Gas Conservation Commission Regulations Title 20 - Chapter 25. Further, no offsetting wells within the AOR (1/4 mile radius) may be drilled into or below the arresting zone (lower Kingak Formation) as depicted in Exhibit C-2 of the application) unless directed by EPA. B. CORRECTIVE ACTION The applicant has identified no wells in the Area of Review which require corrective action in order to prevent fluids resulting from Colville River injection from moving above the confining zone. If the applicant later discovers that a well or wells within the Area of Review require(s) corrective action to prevent this fluid movement, as described in 40 CFR 144.55, then the applicant shall inform the EPA upon such discovery and provide a corrective action plan for EPA review and approval. If the EPA or the applicant discovers that fluids resulting from Colville River injection have moved above the confining zone along the wellbore of a well within the Area of Review, then Colville River injection shall cease until the fluid movement problem can be diagnosed and corrected. C. WELL OPERATION 1. Prior to Commencing Injection Injection operations pursuant to this permit may not commence until: a. Construction is complete and the permittee has submitted two copies of COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-9), see APPENDIX; and (1) The Director has inspected or otherwise reviewed the new injection well and finds it is in compliance with the conditions of the permit; or (2) The permittee has not received notice from the Director of intent to inspect or otherwise review the new injection well within thirteen (13) days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the permittee may commence injection. b. The operator demonstrates that the well has mechanical integrity as described below and the permittee has received notice from the Director that such a demonstration is satisfactory. The permittee shall notify EPA two weeks prior to conducting this initial test so that an EPA representative may be present. In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig) for not less than thirty minutes. Pressure shall show a stabilzing tendency. That is, the pressure may not decline more than 10 percent during the test period and shall experience less than one-third of its total loss in the last half of the test period. If the total loss exceeds 5% or if the loss during the second 15 minute period is equal to or greater than one half the loss during the first 15 minutes, the permitee may extend the test period for an additional 30 minutes to demonstrate stabilization.. c. The operator has conducted a step-rate test and submitted a preliminary report to EPA which summarizes the results. This page modified effective December _, 1999 ~ ~'~ ~'"" . . . Page 14 of 16 2. During Injection The injection facility shall be manned 24 hours per day by trained and qualified operators during injection. 3. Mechanicallntegritv a. Standards The injection well(s) must have and maintain mechanical integrity pursuant to 40 CFR 146.8. b. Prohibition Without Demonstration of Mechanical Integrity Injection operations are prohibited after the effective date of this permit unless the permittee has conducted the following tests and submitted the results to the Director: (1) To detect leaks in the casing, tubing, or packer, the casing-tubing annulus must be pressure tested to at least 3,500 psig for thirty minutes. Pressure shall show a stabilzing tendency as described in II.C.1.b, above. This pressure test is required at a time interval of no more than 12 months between tests. (2) To detect movement of fluids behind the casing, approved fluid movement tests shall be conducted not less often than annually. Approvable fluid movement tests include, but are not limited to tracer surveys, temperature, noise or other logs. The specific suite of fluid movement tests proposed to satisfy this requirement are subject to prior approval by the Director. Tracer surveys shall be run at injection pressures at least equal to the maximum continuous injection pressure observed in the well in the previous 6 months and the tracer concentration shall be sufficient to ensure detection behind the casing. Copies of all logs shall be accompanied by a descriptive and interpretative report. The initial operational fluid movement tests shall be completed not less than three nor more than nine months after initiation of operation. In the event these initial tests are held after less than six months of operation, tracer surveys shall be run at injection pressures at least equal to the maximum continuous injection pressure observed in the well since the beginning of operation. c. Terms and Reporting (1) Two (2) copies of the log(s) and two (2) copies of a descriptive and interpretive report of the mechanical integrity tests identified in 3.b shall be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated by the pressure test in 3.b.(1) any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The permittee shall report the results of such tests within 45 days of completion of the tests. This page modified effective December _' 1999 . . Page 15 of 16 (3) After the initial mechanical integrity demonstration, the permittee shall notify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations. Such notice must include an indication of the suite of fluid movement tests the permittee proposes to use. In the event that any of the proposed tests has not been previously approved by the Director, this notice shall include: (a) a complete description of such proposed tests, (b) available evidence supporting the applicability of the proposed test, and (c) a description of such back- up procedures as the permittee deems necessary to adequately demonstrate mechanical integrity in the event that the proposed tests fail to do so. (4) The Director will notify the permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this 13 day review period. If the Director does not respond within 13 days, injection may continue. (5) In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the permittee shall halt operation immediately and shall not resume operation until the Director gives approval to resume injection. (6) The Director may, by written notice, require the permittee to demonstrate mechanical integrity at any time. 4. Injection Intervals Injection shall be limited to the Ivishak and Sag River Formations, as depicted in Exhibits C-1 and C-2 of the application. 5. Injection Pressure and Rate Limitations The maximum injection pressure, measured at the wellhead, shall not exceed 3200 pounds per square inch (psig). Further, injection pressures and rates shall be limited as needed to prevent the initiation of new fractures or propagation of existing fractures in the upper confining zone (above the J3 marker which separates the upper and lower Kingak Formations) depicted in Exhibit C-2 of the permit application. The permittee shall continuously monitor both the injection rate and pressure. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non-freezing solution. A positive surface pressure up to 1500 psig is authorized. 8. Iniection Fluid Limitation No substance other than those non-hazardous wastes noted in the permit application shall be injected. Neither hazardous waste as defined in 40 CFR 261 nor radioactive waste other than naturally occurring radioactive material (NORM) from pipe scale and sludge shall be injected for disposal. This page modified effective December _' 1999 . . Page 16 of 16 D. MONITORING 1. MonitorinQ Requirements Samples and measurements collected for the purpose of monitoring shall be representative of the monitored activity. 2. Continuous Monitoring Devices Continuous monitoring devices shall be installed, maintained, and used to monitor injection pressure and rate, and to monitor the volume of the non-freezing fluid in the annulus between the tubing and the long string casing. Calculated flow rates and calculated volumes are not acceptable. 3. Alarms and Operational Modifications a. The permittee shall install, continuously operate, and maintain alarms to detect excess injection pressures and rates and significant changes in annular fluid volume. These alarms must be of sufficient placement and urgency to alert operators in all operating spaces. b. The permittee shall install and maintain an emergency shutdown system to respond to losses of internal mechanical integrity as evidenced by deviations in the annular fluid pressure. c. Plans and specifications for the alarms and pressure relief valve shall be submitted to the Director prior to the initiation of injection. E. REPORTING REQUIREMENTS 1. Quarterly Reports The permittee shall submit quarterly reports to the Director containing the following information: a. Monthly average, maximum and minimum values for injection pressure, rate, and volume shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Graphical plots of continuous injection pressure and rate monitoring. c. Raw monitoring data in an electronic format. d. Physical, chemical, and other relevant characteristics of the injected fluid. e. Any well work over or other significant maintenance of downhole or injection-related surface components. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests. g. Any other tests required by the Director. 2. Report Certification All reporting and notification required by this permit shall be signed and certified in accordance with Part I. E.15., and submitted to the following address: Manager, Ground Water Protection Unit This page modified effective December _' 1999 . . U.S. Environmental Protection Agency (OW-137) 1200 Sixth Avenue Seattle, Washington 98101 This page modified effective December _' 1999 Page 17 of 16 Enclosed are EPA Forms: 7520-7 7520-8 7520-9 . . APPENDIX REPORTING FORMS APPLICATION TO TRANSFER PERMIT INJECTION WELL MONITORING REPORT COMPLETION FORM FOR INJECTION WELLS This page modified effective December _, 1999 Page 18 of 16 #7 . · . 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 In Re: 4 PUBLIC HEARING COLVILLE RIVER UNIT AREA 5 INJECTION ORDER. 6 7 8 9 10 APPEARANCES: 11 Commissioners: 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska October 19, 1999 9:05 o'clock a.m. MR. ROBERT N. CHRISTENSON, CHAIRMAN MR. DAVID W. JOHNSTON * * * * * * · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 " JI .- ~ll1G~\L_ e e 2 · 1 PRO C E E DIN G S 2 (On record 9:05 a.m.) 3 CHAIRMAN CHRISTENSON: Good morning everybody. 4 This is a hearing for the Alpine Injection Order. It's 5 Tuesday, October 19th. We're at 3001 Porcupine Road. It's 6 about five after 9:00. So we would like to call this hearing 7 to order. 8 During the course of the hearing, we'll have -- we can 9 either have sworn or unsworn testimony. The Commission will 10 give greater weight to sworn testimony than the unsworn 11 testimony in its deliberations. All witnesses to be sworn will 12 give their name and whom they are representing. If you would 13 like to testify as an expert witness, please state your · 14 qualifications and the Commission will rule on the degree 15 whether you're an expert or not. 16 And I think that's all this morning. So Mr. Ireland, 17 if you would like to start. 18 MR. IRELAND: Great. Good morning everyone, 19 Commissioners. 20 CHAIRMAN CHRISTENSON: Good morning. 21 MR. IRELAND: Pleased to be here today. My 22 name is Mark Ireland. I'm representing ARCO. And I guess I 23 would like to present sworn testimony. 24 CHAIRMAN CHRISTENSON: Okay. State your name. 25 MR. IRELAND: Mark Ireland. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 3 · 1 2 3 4 lS. (Oath administered) MR. IRELAND: I do. I'm excited to be here. I think our whole Alpine team We've made a lot of great progress over the last few 5 years, and I would like to do a brief introduction before the 6 rest of the team goes through the details, technical details, 7 of the presentation today. 8 First of all, after I'm done speaking, Doug Knock will 9 give a brief geologic overview of the field. He'll be followed 10 by Mike Erwin who will talk about the operations. Scott Redman 11 then will talk about the reservoir. He'll be followed by Dr. 12 Fred Stalkup who is going to discuss the EOR certification that 13 he did for IRS purposes for ARCO, and then Scott will summarize · 14 at the end. 15 The Alpine Field was discovered in 1994. It's located 16 in the Colville River Delta about 35 miles west of Kuparuk 17 Field. The owners are ARCO with 78 percent and Anadarko with 18 22 percent working interest. Royalty owners are the State of 19 Alaska, the Arctic Slope Regional Corporation, and the Kuukpik 20 Village Corporation. We're on track for our field start-up in 21 mid 2000 less than a year away. And also of note, Alpine 22 represented the largest onshore oil discovery in the U.S. this 23 decade. 24 Since the last time we were before the Commission for 25 our pool rules, we've changed our plan of development, revised · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 4 · lour plan of development. As a resultl we/re even more excited 2 about the field/s performance. We/ve increased our reserve 3 estimates from 365 to 429 million barrels. We forecast the 4 peak production rate to increase from our original estimate of 5 701000 barrels a day to now 801000 barrels a daYI which we 6 would hit in 2001. We planned a miscible gas injection EOR 7 project at field start-up which you/ll hear a lot more about in 8 a few minutes. And also we/ve changed the drilling plan to be 9 all horizontal wellsl more wells on closer spacingl and with 10 longer horizontal sections than originally discussed. 11 COMMISSIONER JOHNSTON: The increase in your 12 reservesl is that a result of improvements in your development 13 plan or is it through delineation drilling you have a larger · 14 accumulation? 15 MR. IRELAND: It/s through improvements and our 16 development plan certainly. 17 I would like to give you a brief status on where the 18 construction project stands. We/re over 85 percent complete 19 and have hit all of our major milestones. We/re on target for 20 a mid 2000 start-up. The production facilities are now on the 21 North Slope. That sealift occurred In Augustl and we/re 22 waiting now for winter ice roads to be able to transport those 23 modules into the Alpine Field. 24 CurrentlYI the number of works on the Slope is about 25 3001 and we should peak out at somewhere around 600 later this · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 5 · 1 winter. Drilling is continuing on an ongoing basis. There's 2 nine wells in the field that are completed to date. 3 Some of the things we're proud about with this 4 development, this project was executed using five Alaskan 5 contractors. It was the first large module fabrication in 6 Alaska by APC. Over 75 percent of the total investment here is 7 made here in Alaska, and that's estimated at about $750 million 8 spent in state. In the process, we've created more than 1,600 9 jobs in Anchorage, Fairbanks, Palmer, Nikiski, Nuiqsut, and 10 elsewhere on the North Slope. 11 Here's just a snapshot of the module site on Kenai. It 12 had to be one of the most beautiful construction sites in the 13 world I think but this is earlier this year prior to sealifting · 14 the modules up to the Slope. 15 CHAIRMAN CHRISTENSON: How big was the biggest 16 module weight-wise? 17 MR. IRELAND: Weight-wise, about 3 million 18 pounds I believe. 19 UNIDENTIFIED SPEAKER: Two and a half. 20 MR. IRELAND: Two and a half or so. One of the 21 things we're most proud about with Alpine is our environmental 22 record and the care we've taken in a sensitive part of the 23 North Slope. The surface footprint will be less than one 24 percent of the 40,000 acre field. The pipelines that cross the 25 Colville River were directionally drilled under the river which · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 6 1 was a first in an arctic permafrost environment. 2 We got an interesting picture. Something that those of 3 us that are used to drilling wells for oil field development 4 aren't used to seeing is a drill bit coming back out of the 5 ground at you. But this is the result of the successful 6 breakthrough of one of those horizontal pipeline crossings that 7 was drilled into the Colville River and came out within a 8 matter of feet within their exact target on the far side of the 9 river. 10 Vertical pipeline expansion loops is another creative 11 idea first for this project. Here's a picture of what those 12 looked like. These are the couple benefits, one as you can 13 see. They're about 30 feet or so high allowing easy migration 14 of caribou and other species. Also it eliminates the need for 15 valves on either side of river crossings and so on, which as 16 you may know is the major source of leaks in pipelines 17 traditionally. So we've eliminated -- we've made a safer 18 pipeline and at the same time made it easier for crossings. 19 The development is roadless. We will not be connected 20 back to the rest of the infrastructure on the North Slope 21 except for in the wintertime with the ice roads that get put 22 in. Other than the winter time, access is by air only. And 23 also we're in a zero discharge development plan. 24 Finally, I would like to thank some of the many other 25 groups that are involved with this project that made it MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 2 3 4 5 6 7 8 9 10 11 12 13 · 14 · e e 7 1 possible. First of all, our partner, Anadarko. Also on the construction side Alaskan Contractors, APC Houston, Michael Baker, APEL, Nuiqsut Constructors. On the drilling side Doyon, MI, Schlumberger, Dowell, and Baker. Of course, the State of Alaska, Arctic Slope Regional Corporation, Kuukpik Village Corporation, and the City of Nuiqsut who -- without whose cooperation we would not have been able to proceed with the development. That's all I had to present. If there are any questions, I'll turn it over to Doug. CHAIRMAN CHRISTENSON: Okay, sir. COMMISSIONER JOHNSTON: Just out of curiosity, Mike, the City of Nuiqsut is going to benefit directly from this development because of the ability to pull off gas off the 15 reservoir. Have they hooked up yet to the field? Are they 16 taking advantage of that gas at this time or..... 17 MR. IRELAND: Yes. They have plans in place. 18 Some of the pipeline's been laid. It hasn't all been laid. 19 COMMISSIONER JOHNSTON: Okay. So..... 20 MR. IRELAND: The part on VSMs coming south out 21 of the field is in place. They still have to cross the river 22 and make the connections in the village but, yes, that's 23 something that they are eagerly awaiting, and will allow them 24 to get a clean cheap source of fuel. 25 COMMISSIONER JOHNSTON: Yeah. Having held a MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 8 · 1 2 3 4 5 6 7 8 number of different public hearings in Nuiqsut in the past, I'm acutely aware that they are very, very concerned about getting cheap source of fuel so this is a pretty amazing thing for the village I would think. MR. IRELAND: Yeah. They're..... COMMISSIONER JOHNSTON: So you think they're, what, a year out? MR. IRELAND: I think at least a year out, 9 something like that. It will be a phase transition then to get 10 all the distribution system put in place in the village itself. COMMISSIONER JOHNSTON: It will be interesting 11 12 to see that thing unfold. All right. Thank you. MR. IRELAND: Uh-hum. 13 · 14 15 16 17 18 your name. 19 MR. KNOCK: Good morning. CHAIRMAN CHRISTENSON: Good morning. MR. KNOCK: I would like to testify here today. CHAIRMAN CHRISTENSON: Okay. Would you state MR. KNOCK: Doug Knock. (Oath administered) 20 21 MR. KNOCK: I do. CHAIRMAN CHRISTENSON: Good. Proceed. 22 (Off record comments) 23 MR. KNOCK: Some of you may not be aware that 24 25 our company motto has changed recently. Just recently. I MET ROC 0 U R T R E P 0 R TIN G, INC. · 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 9 · 1 thought that was important to show you that. We are still safe 2 but that's the main thing. 3 The operator of Alpine is ARCO Alaska presently. The 4 surface owners are the State of Alaska and Kuukpik Corporation. 5 Kuukpik on the western side of the field in the state on the 6 eastern side of the field. And an affidavit of Notice to 7 Surface Owners has been filed. Mark Ireland already went over 8 some of that. 9 Here's a location map for Alpine. The pool is mostly 10 shown in green. Alpine is approximately 25 miles west of the 11 Kuparuk River Unit. The boundary -- the NPRA boundary is the 12 Nechelik channel of the Colville River. They are going through 13 the western side of the Alpine field or the Alpine pool I · 14 should say. And the Colville River Unit is shown in red around 15 the Alpine Oil Pool. 16 These are the Alpine Oil Pool sections as selected by 17 ARCO for pool rules. And the Colville River Unit is shown once 18 again in red around the sections selected for pool rules. 19 This is a map showing the proposed Alpine development 20 wells. The configuration is a line drive of horizontal 21 producers and injectors all roughly 3,000 feet long. The 22 producers are in green and the injectors are in blue. 23 It doesn't quite -- this is the Bergschrund 1 well, a 24 type log. The Alpine sandstone is the uppermost of three Upper 25 Jurassic sandstone bodies: Nechelik, Nuiqsut, and Alpine in · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e - 10 · 1 the Colville Delta Area proper. Each of these sand bodies is 2 east west elongate and related to shallow marine and shore face 3 deposition. Alpine ranges in thickness from about 30 feet to 4 100 feet thick in the Alpine Oil Pool area. 5 This is a blowup of the Bergschrund 1 type log. The 6 Alpine pool is bracketed by the top Alpine pick on the top and 7 the base or the Kingak E pick along the base. These picks are 8 made on gamma ray and resistivity logs 1 LWD logs mostly. 9 Overlying Alpine is mudstones of the Miluveach formationl and 10 underlying Alpine are soapstones and very fine sandstones of 11 the Upper Kingak. Alpine itself is a clean quartz-richl very 12 fine defined grain sandstone generally thoroughly bioturbated. 13 COMMISSIONER JOHNSTON: So what are you · 14 specifically calling your confinement zones then? 15 MR. KNOCK: Let/s go back to the previous 16 diagram. Your confinement zones would be the Miluveach 17 interval which is below the LCU. The LCU is right at the base 18 of the Kuparuk interval. So you/ve got the Miluveach mudstone. 19 The Kuparuk is non-pay. There/s a thin lag in the Alpine area. 20 Then you have the Kaluvik shale above that and the HOZ above 21 that so you/ve got 400 to 500 feet of mudstone effectively 22 before we hit our first significant sandstone in the Lower 23 Torok and the Albian sands. To define an interval is a 24 combination of lower cretaceous mudstone formations of about 25 500 feet thick. And below we have the -- the Kingak is below · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 11 · 1 us. We have non-reservoir sand in the Nuiqsutl in the pool 2 area a couple hundred feet below Alpine. And the Nechelik is 3 slightly more prospective but still not prospective in the 4 Alpine pool area. And that/s 400 feet below the Alpine 5 sandstone proper. So the soapstones and very fine sandstones 6 of the Kingak are the defining interval below Alpine. 7 This is a top structure map on Alpine. Depth-wisel 8 Alpine averages about seven feet 7/000 feet subsea TVD below 9 the surface. The structure dips at approximately one degree 10 from northeast to southwest. The faults are generally 11 northwest trending normal faults often down to the west with 12 throws averaging 20 to 30 feet. Alpine is a stratigraphic trap 13 with updip pinchout of the sandstones into shales of the · 14 Kingak. And no oil water contact or gas oil contact has been 15 penetrated in the field area to date. 16 And with thatl I conclude my testimony. 17 COMMISSIONER JOHNSTON: Did you wish your 18 testimony to be considered or did you wish the Commission to 19 consider you an expert witness this morning? 20 MR. KNOCK: Yes. 21 COMMISSIONER JOHNSTON: Okay. Why don/t you 22 state your qualifications for us and then weIll rule on that. 23 MR. KNOCK: Once againl my name is Doug Knock. 24 I have a Masterls Degree in Geology from the University of 25 Alaska-Fairbanks. I have over 12 years of experience working · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 12 · 1 for ARCO Alaska on a variety of projects. 2 COMMISSIONER JOHNSTON: And specifically how 3 long have you been involved with Alpine? 4 MR. KNOCK: lIve been working at Alpine for a 5 little over two years now. 6 COMMISSIONER JOHNSTON: I have no objection. 7 CHAIRMAN CHRISTENSON: Okay. Consider you an 8 expert witness. 9 MR. KNOCK: Thank you. 10 MR. ERWIN: Good morning. My name is Mike 11 Erwin. I would like to be considered an expert witness. 11m a 12 1977 graduate of Louisiana State University with a degree 13 Bachelorls Degree in Civil Engineering. 22 years in oil field · 14 experience I 11 in Alaskal and the last two on the Alpine 15 projectl and 11m a registered professional engineer for the 16 State of Alaska. 17 CHAIRMAN CHRISTENSON: Okay. Dave? 18 19 Alpine? 20 21 22 Thank you. 23 COMMISSIONER JOHNSTON: And how long with MR. ERWIN: Two years. COMMISSIONER JOHNSTON: Two years. Okay. No objection. CHAIRMAN CHRISTENSON: Okay. Consider you an 24 expert witness. Do you wish to be sworn? 25 MR. ERWIN: Yes. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 13 · 1 CHAIRMAN CHRISTENSON: State your name. 2 MR. ERWIN: Michael Erwin. 3 (Oath administered) 4 MR. ERWIN: Yes, sir. 5 CHAIRMAN CHRISTENSON: Okay. Please proceed. 6 MR. ERWIN: I would like to speak briefly this 7 morning on a few of the operational matters associated with the 8 flood program we're proposing. The injection wells for the 9 Alpine field have already been discussed at length in the pool 10 rule hearing and will be drilled and completed in accordance 11 with Conservation Order 443 as regards to where we'll set pipe 12 and how we'll cement it. Subsurface safety valves will be 13 tested every six months. We'll be surveying reservoir · 14 15 16 17 18 pressures in each injection well prior to it going on service, and all the wells will be appropriately abandoned. This is a typical injection well completion as proposed showing the location of the tubulars with subsurface safety valve and the packer, and as we've noted, all the horizontal 19 all the completions will be horizontal. 20 Injection pressures are expected to range from 21 approximately 4,000 psi when the wells are on gas injection or 22 miscible injectant to 1,800 when the wells are on seawater. 23 The plant discharge pressures are expected to be 4,500 for gas 24 and in the 2,500 psi range on water. We anticipate having more 25 than adequate pressure to inject fluids into the Alpine · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 14 1 reservoir. 2 It is likely that many of the injectors will, in fact, 3 fracture within the reservoir. It does not present undue 4 concerns for the Alpine because there are - - it's been well 5 established that there are no fresh water resources within the 6 confines of the Colville River Unit that could be impacted by 7 any escaping fluids. We think it's very straightforward that 8 the fractures -- any fractures that do begin or initiated 9 within the Alpine Oil Pool will be contained entirely within 10 that pool. And that's substantiated by core testing, log 11 analysis, and fracture modeling. 12 This is a summary of the lab results of work done by 13 Taratech in Sunbury under the guidance of our research center 14 in PIano. I call your attention to the static Poisson's ratio 15 and the stress contrast between the shales above and the sands 16 below which gives us quite a dramatic stress contrast. That's 17 probably better displayed on a log format. This analyzed 18 diplesonic comes from the Bergschrund I, and on the far right 19 track displays the pore pressure as a blue solid line and the 20 fracture pressure which would be the horizont- -- minimal 21 horizontal stress on the red line. The thing to note is the 22 stress contrast between the Alpine formation which is here, and 23 the over and underlying shales. It turns out that there's an 24 approximately 700 psi net pressure difference between the 25 Alpine sand and the shales around it, the Alpine sandstone METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 12 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · e e 15 1 being substantially more brittle and prone to fracture than the 2 more ductile shales above and below. 3 Fracture modeling conducted in Plano using the values 4 of rock properties that we've identified off the logs and cores 5 suggests that in a 39 foot tall Alpine interval, you would 6 expect to see fracturing on the order of 55 feet tall at a five 7 barrel a minute rate which would carry into the overlying 8 shales approximately 16 feet, perhaps eight feet above and 9 eight foot below, before that shale -- that fracture is 10 bounded. And this assumed almost two years of injection. 11 Unless there are any further questions, that concludes my testimony this morning, and I would turn it over to Scott Redman. COMMISSIONER JOHNSTON: How would you describe the shape of that fracture? MR. ERWIN: Elliptical. COMMISSIONER JOHNSTON: Is it planar in or is it better to think of it as kind of a system of fractures? Are you talking one fracture or a system of fractures? MR. ERWIN: The model is only going to treat it as a planar system. COMMISSIONER JOHNSTON: Right. Okay. MR. ERWIN: But in practice in the field, I would expect it to be a network. COMMISSIONER JOHNSTON: So it's best to think MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 16 1 of this as a zone of influence and not necessarily just one 2 singular planar fracture. 3 MR. ERWIN: Yes. 4 COMMISSIONER JOHNSTON: Right. Okay. Thank 5 you. 6 7 8 9 Redman. MR. ERWIN: Thank you very much. CHAIRMAN CHRISTENSON: Good morning. MR. REDMAN: Good morning. My name is Scott I'm a reservoir engineer with ARCO. I would like to 10 present sworn testimony. 11 (Oath administered) 12 MR. REDMAN: I do. 13 CHAIRMAN CHRISTENSON: Please go ahead. 14 MR. REDMAN: I would also like to be considered 15 an expert witness. 16 CHAIRMAN CHRISTENSON: Good. Would you state 17 your qualifications, please? 18 MR. REDMAN: I'm a 1983 graduate of Oregon 19 State University with a Degree in Civil Engineering. I have 20 over 15 years of facility operation and reservoir engineering 21 experience, all with ARCO. Nine years reservoir, seven at 22 Prudhoe, and then the last two at Alpine. 23 CHAIRMAN CHRISTENSON: Okay. 24 COMMISSIONER JOHNSTON: No objection. 25 CHAIRMAN CHRISTENSON: No objection. We'll MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 17 1 consider you an expert witness. 2 MR. REDMAN: All right. 3 Please proceed. CHAIRMAN CHRISTENSON: 4 MR. REDMAN: Today I would like to go over a -- 5 sure, get clipped here -- the -- a description of the proposed 6 operations for Alpine, talk a little bit about our fluids that 7 we'll be injecting into the reservoir, and talk about 8 incremental hydrocarbon recovery for the Alpine reservoir. 9 Summary of our proposed operations that I'm going to 10 discuss include our field development plan, the recovery 11 mechanisms for Alpine, miscible injectant supply. We're going 12 to have an indigenous supply to Alpine. We'll talk about EOR 13 project right at the beginning at field start-up. Talk a 14 little bit about the proper staging for the EOR project, 15 discuss injectivity issues, show a little bit about solvent 16 supply equipment and staging of the solvent supply, and talk 17 about disposal operations. 18 This next slide describes our field development plan. 19 We're planning on 112 development wells. They're all 20 horizontal in a direct line drive pattern configuration with 21 1,500 feet spacing between injector and producer rows, and the 22 average well spacing is 135 acres. The new EOR facilities that 23 we're putting in in addition to this include a Joule-Thompson 24 fuel gas unit to recover enrichment components from the field 25 gas, a new LP compressor after cooler, and piping modifications MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · e e 18 1 that are going to increase our condensate recovery, and a 2 pipe -- pipelines that will go to the two drill sites, the 3 supply in line, and then the new strategy going from a 4 waterflood in the center of the field and peripheral gas 5 injection to a miscible gas water alternating gas injection 6 strategy. 7 Again, this exhibit shows the pattern configuration 8 that we plan to use, and it is a direct line drive, and 9 producers are shown in blue and injectors in green. 10 The recovery mechanisms for Alpine include waterflood 11 recovery. The type pattern model simulations indicate that on 12 waterflood recovery we could get 45 to 50 percent of the 13 original oil in place. What we observe is is a low mobility · 14 ratio. We get excellent volumetric sweep efficiency with 15 waterflooding but we leave high residual saturations behind on · 16 the order of 35 to 40 percent. Miscible WAG is preferable 17 compared to waterflood. It gets recoveries roughly 10 percent 18 higher in the order of 55 to 60 percent of original oil in 19 place. The miscible injectant tends to reduce the residual 20 saturations in the gas swept zones and also tends to swell the 21 oil up so you leave less stock tank barrels behind in the 22 residual oil. 23 This next slide shows a stillstand pattern simulation 24 with oil recovery as a function of hydrocarbon pore volumes 25 injected. In blue you see a base waterflood curve, and in METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 1 2 3 4 5 6 · 14 15 16 17 18 19 20 21 22 23 · e e 19 green you see a miscible flood curve that has been taken out to 23 percent hydrocarbon pore volume MI slug size. And you can see that you're getting an incremental roughly 10 percent oil in place over waterflood. To generate our miscible injectant supply, we're using produced oil, and in doing that, there's some production 7 priorities that we have. First is is we want to maximize the 8 amount of saleable oil production today out of the field. The 9 next is is we want to maximize the amount of enriching 10 components that we can recover from the field gas system to 11 blend into the MI. And then finally we want to be able to 12 maximize our MI rates while staying above a target minimum 13 miscibility pressure. So we're going to ensure that our MI stream is miscible with the oil at average reservoir conditions. The impact of the EOR facilities that we're putting in include a Joule-Thompson unit that is going to recover enriching components from the fuel gas system to be blended back to increase our MI rates, and piping modifications at an LP cooler expansion that will increase saleable oil rates by 500 to 1,000 barrels a day over not putting in the EOR facilities. This next slide shows the benefit of enriching the 24 miscible injectant. As you can see, this plot shows a plot of 25 incremental recovery versus enrichment fraction expressed as a MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 20 . 1 fraction of C2+. And K lean stands for Kuparuk lean gas. Lean 2 gas is gas discharged out of the compressors at Alpine. 3 Tailgas is if we wouldn't have put the EaR facilities in, and 4 MI is the blended MI composition. You can see that you're 5 increasing the enrichment level, and at the same time you're 6 increasing the oil recovery you're getting from the injectant. 7 Next slide shows our reasons for starting this project 8 early in the life of the field rather than waiting until later. 9 First of all, we want to be able to maximize the MI supply. In 10 doing that, in putting in the JT unit early, we're able to 11 recovery those enriching components rather than having them 12 lost to the system by burning as fuel gas. And the MI is made 13 from the oil so you want to start that early in the life of the 14 project where you have high oil rates. Initial gas injection 15 needs to be in the core area of the field. The original gas 16 the original development plan would have put gas out on the 17 periphery of the field in a continuous gas injection mode, and 18 if you would have done that, you wouldn't have been able to 19 recover those components later to do MI in the part of the 20 field. It would have been trapped. And finally, you want to 21 convert to miscible WAG injection before water breakthrough 22 severely restricts the production rates in the wells. And to 23 illustrate that last point, I have a type model plot. On top I 24 have oil and water rates as a function of time, and on the 25 bottom plot I have hydrocarbon pore volume injection gas plus METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 21 · 1 water fraction as a function of time. And what you can see is 2 that early in the life of the field you have high oil and -- 3 oil production and water injection rates. After you get to 4 water breakthrough though, your through put rates decrease by a 5 factor of four. So if you wait until after waterflood 6 breakthrough, the flood rates will be too slow to economically 7 recover EOR reserves. 8 Next, I want to talk about the proper staging of the 9 EOR project. The type model results give some indication of 10 how to optimally inject to get the most recovery. And the 11 first thing that you want to do is pre-inject about a 20 12 percent hydrocarbon pore volume slug of water prior to miscible 13 injectant -- injection. Next, once you're on miscible · 14 injection, you need a very low WAG ratio, and I'll illustrate 15 that in a minute with an exhibit. First of all, gas 16 substantially reduces water injection in the type models. So 17 after you start WAG, your water injection rates are going to be 18 lower. During WAG you maintain voidage balance by injecting 19 higher rates on the gas cycle. And this is a model effect. We 20 still need to validate this in the field. We may get 21 pleasantly surprised that water injection rates don't fall off 22 as much as in the simulator but this lS what we're planning on 23 now. In terms of desirable MI slug size, 20 to 30 percent 24 appears to be optimal. And after you've injected your 25 desirable slug size, you're either going to convert to · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 22 1 chasewater or if it's available lean gas in the future. 2 This next slide shows incremental oil recovery as a 3 function of the amount of water you pre-inject before you start 4 WAG for three different hydrocarbon slug sizes: a 20 percent, 5 a 25 and a 30 percent, and also a discounted oil recovery as a 6 function of that water pre-injection slug. And you can see 7 that on a undiscounted basis that you can - - you need to pre- 8 inject at least a 10 percent slug of water and probably less 9 than a 25 percent slug of water to get the good ultimate 10 recovery. But in terms of optimal oil rates, if you look on a 11 discounted basis, it's a little clearer that you want to get 12 into maximum -- a slug size of around 20 percent HPV in order 13 to be optimal. 14 This next slide shows water injection rate as a 15 function of time for a waterflood and a miscible flood. And 16 what you can see is that when -- as you're putting the pre- 17 injection of water in, you know, the water and WAG rates for 18 the two cases are the same. When you start on WAG, your water 19 rates are going to drop down significantly. And you're making 20 up for that with higher rates on the gas cycle so that the 21 flood rates if anything may be a little bit higher on WAG than 22 on waterflood. And then finally in the end, you go to - - after 23 you put your slug size in you'll go to chasewater the same way. 24 But as you can see there, the timing of when you decide to 25 start WAG is going to control the kind of volume of water you MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 23 · 1 can get in. 2 If you look at our surveillance plans, during the pool 3 rules hearings, we discussed o~r plans for pressure monitoring, 4 injector and producer profile monitoring, and voidage balance. 5 The additional surveillance for this EOR project include 6 monitoring the injection rates and compositions of the gas, 7 monitoring the GOR and WOR of ~he wells, and monitoring the 8 slug sizes of both water and gas that are put into the 9 patterns. And then that is going to allow you to pick optimum 10 times to stage In the WAG expa~sion. 11 We talked about optimu~ MI slug sizes and optimum total 12 slug sizes for the field. The first observation is is for MI 13 you want to get a 15 to 20 percent hydrocarbon pore volume slug · 14 to be most efficient. You get limited benefits beyond maybe a 15 30 percent hydrocarbon slug. And on a total basis, water plus 16 gas, you start to get to pretty low oil rates beyond, say, a .8 17 HPV of water injection. And if you start early on gas, you may 18 prevent getting this desired water injection in. 19 This next slide shows an EOR recovery curve with 20 incremental recovery as a func~ion of HPV slug size. And you 21 can see that putting in a 15 to 20 percent slug, you get most 22 of your incremental recovery. You continue to go up the curve 23 from 20 to 30 percent and then it's starting to break over 24 about 30 percent incremental recovery. 25 Next I want to talk about the EOR facilities that we · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907,1 276-3876 · 12 13 · 14 15 16 17 · e e 24 1 put In. Again, to review, we're putting in a JT fuel gas unit, 2 low pressure compressor after cooler piping modifications and 3 MI to the two drill sites. 4 And I want to show that on the next exhibit which shows 5 a process schematic for Alpine. And just to go through it 6 quickly. It's a one frame process where oil enters at a first 7 stage separator. Gas comes off the top of that separator and 8 goes through the gas train shown in yellow there through three 9 stages of compression. The oil continues shown in the -- kind 10 of the green blocks there, through a heater to a low pressure 11 separator, and then through oil dehydration and off to sales. And gas off the LP separator originally was going through an LP compressor and then back over to the first stage compressor. In red here, we see the EOR facilities we're adding. First, the JT fuel gas unit is going to take gas off of the discharge of the second stage, and it's going to cool it down, extract enriching components, and then the leaner gas off of that will 18 be used as fuel gas. And the enriching components are then 19 pumped up and blended to make the miscible injectant. The 20 cooler showed in red there and the piping modifications to 21 route that cooler to the condensate flash drum allow you to 22 take the relatively rich gas off of the low pressure system and 23 recover some additional condensate in the condensate flash drum 24 that can then be recovered by recycling it into the oil WAG off 25 of the first stage separator. MET ROC 0 U R T R E PO R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 25 1 This next plot shows a MI supply forecast versus time, 2 and you have MI injection rate and millions of standard cubic 3 feet per day versus time. And what you see is a ramp up up to 4 70 or 80 million a day. Late in the life of the field, you 5 tend to go short on solvent. You -- this solvent supply could 6 be increased by better than expected performance in the field, 7 or if other satellites become available around Alpine, the -- 8 to process those satellites you may end up taking their gas and 9 reinjecting it into the Aline Field and that could increase gas 10 supply. 11 CHAIRMAN CHRISTENSON: But this is just the 12 Alpine Field itself. 13 MR. REDMAN: This is the Alpine Field itself. 14 Our field pattern expansion strategy needs to be 15 staged. In the core area of the field, we plan to start up 16 three to five wells on continuous gas injection. The remaining 17 wells would start up on water. After you've got the 20 percent 18 pre-injection of water into some of the higher perm patterns 19 In, say, the first two to four years, you'll convert those 20 patterns to WA- -- admissible WAG, and then as the lower 21 permeability patterns reach their target in five to seven 22 years, you'll convert them to miscible WAG. And after they've 23 hit a target slug size, they'll be turned over to chasewater. 24 The strategy in the peripheral area is that you don't start 25 drilling in the periphery for four to five years after start up MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 26 · 1 because you're drilling core wells. All the injectors will 2 initially start up on water injection, and you'll have 15 to 20 3 wells. The -- these wells would be converted to WAG or 4 continuous gas in the future depending on what the water 5 injectivity and MI supply are out in that later time period. 6 This next picture just shows the -- what we're calling 7 as the core area enclosed in the black polygon and the 8 peripheral wells around the edge of the field. 9 Finally, for disposal operations, again, it's going to 10 be consistent with our previously approved and permitted 11 operations for our disposal well, WD2, and the disposal would 12 be confined to the Ivishak zone of the Sadlerochit Group. 13 Next, I want to talk a little bit about our fluid · 14 analysis. We'll be injecting both Kuparuk seawater and 15 miscible injectant into the field. And the next few slides I 16 want to talk a little bit about our miscible injectant 17 criteria. 18 To determine miscibility for reservoir oil and gas, we 19 set up some slimtube experiments and we did two slimtube 20 experiment sets for Alpine. From these we were able to get a 21 match between our equation state characterization and the 22 slimtube results, and from that then we used an analytical 23 method to determine what the minimum miscibility and enrichment 24 was for other gas compositions different than the two slimtube 25 series that we ran. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 27 1 This next plot summarizes our original lean gas Alpine 2 slimtube. And the blue dots -- initially there were two 3 slimtube data points run in the ARCO lab, and they indicated 4 that potentially you had a minimum miscibility pressure that 5 was maybe around 4,000 pounds. And subsequent to that, we did 6 another full set of experiments at core lab, and that comprised 7 six different slimtube runs shown in red. And those clearly 8 showed that the one point -- one ARCO pointed about 3,500 9 pounds is an error. And that the minimum miscibility pressure 10 is approximately 3,500 pounds for this solvent. And with that, 11 we've got a match with our equation of state with the slimtube 12 simulation shown in pink. And you can see that the breakover 13 point is the same. The -- but there is a difference in slope 14 between the core lapse data and that our slope there but 15 that's more of a function of the relative perm that you assume 16 for the slimtube. The key -- the important thing for the 17 thermodynamics is they get that breakover point right at 3,500, 18 and the equation of state does that. 19 Our rich slimtube data was a composition that was -- 20 added enriching components to the lean gas, and what you saw 21 was is that this was miscible all the way down to 2,000 pounds. 22 And you can see in red that you have six slimtube data points 23 that were run, and in pink you have a simulation of this oil 24 where you get a similar breakover point. 25 With those two pieces of data, we use the equation of MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 28 · 1 state in order to come up with the necessary enrichment 2 fraction for different pressures between an MMP of 2,000 and an 3 MMP of 3,500 which we had from the two slimtubes. And the 4 additional lines shown on there are the enrichment required for 5 initial reservoir pressure which is about seven percent 6 enriching fluids, and about 13 percent enriching fluids for the 7 initial solvent composition. 8 Finally, I would like to go through incremental 9 hydrocarbon recovery for the Alpine project. And the topics 10 I'm going to recover are going to be the miscible injectant 11 criterion, fine grade compositional models, our full field 12 model results, and surveillance plans. 13 The expected MI composition is based on a 20 -- 900 · 14 pound MMP, and this is based on reservoir results that predict 15 that we can maintain reservoir pressure about 3,000 pounds and 16 adding a 1,000 pound safety factor to that. The actual MI may 17 be -- have an MMP lower than this if you have additional 18 enrichment components on the fuel gas. 19 COMMISSIONER JOHNSTON: Is there going to be 20 any competition for the enriching components? 21 MR. REDMAN: The -- I guess the key competition 22 that it could be is is down the road you could do an 23 incremental project that improved condensate recovery even more 24 from the facilities. Early on we looked at a condensate 25 stabilizer you could put in and make an even cleaner cut. And · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 29 1 we found that these cooler modifications could get about two- 2 thirds of those benefits for about a tenth of the cost. So we 3 went with that method. But after we get field performance I you 4 would still continue to look for incremental ways to recover 5 condensate. So the balance would be if you could find a new 6 investment project to get more saleable oil out of the systeml 7 then you would look at that. 8 COMMISSIONER JOHNSTON: But at this time I in 9 the near terml there/s no competition for the enriching 10 components at this juncture. 11 MR. REDMAN: Right. Right. WeIll we/re trying 12 to make the most..... 13 COMMISSIONER JOHNSTON: Right. 14 MR. REDMAN: . . . . .oil we can and recover the 15 most enriching components from the fuel gas. 16 COMMISSIONER JOHNSTON: Right. Okay. 17 MR. REDMAN: In terms of ultimate recoverYI we 18 have a type pattern recovery estimates for two different 3-D 19 fine grade compositional models. One represents a 20 transgressive phasis. It/s a higher term phasis for the field. 21 The second is a stillstand phasis which is represents 22 probably the majority of the reservoir and is a lower perm 23 phasis. In both of these phasis you get incremental recoveries 24 on the order of 10 to 12 percent OIP for M WAG over waterflood. 25 For ultimate recoverYI we have full field recovery MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 30 · 1 estimates for the original development plan which was 2 waterflood, the quarry, the field, and do gas cycling on the 3 periphery. The initial estimate for this plan was 365 million. 4 If you look at the new plan with later drilling results, our 5 current estimate for that plan would be 329 million. The 6 revised plan of development is miscible WAG with all horizontal 7 wells, and its current estimate is 429 million. The 8 incremental recovery for the revised plan over the original is 9 roughly 100 million barrels or 11 percent oil in place. 10 In terms of the surveillance plans we need to monitor 11 the progress for the development plan. We put down for oil 12 production rates we're going to run spinners to determine the 13 profiles and do PTA work to determine skin damage. For water · 14 injection rates run spinners to determine profiles and monitor 15 injection rates. For WAG injection rates, we're going to want 16 to look at how the how gas injection decreases after cycles 17 of water injection and how water injection decreases after 18 cycles of gas injection. So in other words, to understand what 19 the interference is between the gas and the water phases for a 20 WAG project. 21 COMMISSIONER JOHNSTON: Would you put up the 22 other slide that you just came off of? The one before -- yeah. 23 MR. REDMAN: This one? 24 COMMISSIONER JOHNSTON: Right. 25 MR. REDMAN: Okay. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 31 1 COMMISSIONER JOHNSTON: The -- I want to make 2 sure that I understand the point that you're trying to make 3 here on that -- the first primary bullet. You're saying the 4 initial 5 million. 6 329. 7 estimate under that -- under the original plan was 365 But the estimate today using that same plan would be MR. REDMAN: Right. 8 COMMISSIONER JOHNSTON: What -- why the lower 9 amount? What is going on? 10 MR. REDMAN: I think one of the pro- -- one of 11 the major things was is the drilling results on 119 to the -- 12 in the northeast portion had thinner transgressive pay than we 13 had expected. It came in at seven feet compared to 30 feet. 14 So you lost some oil in place in that area of the field. 15 The other part of it is this is - - it is an updated 16 model that has, you know, updated, you know, permeability 17 assumptions. It has -- the three -- what I'm trying to do here 18 is the 329 is an apples to apples number with the..... 19 COMMISSIONER JOHNSTON: Right. 20 ... ..429 for a new reservoir MR. REDMAN: 21 model. 22 COMMISSIONER JOHNSTON: But basically the 23 estimates are revised down as a result of this slightly smaller 24 tank and better data. 25 MR. REDMAN: Yes. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 32 · 1 COMMISSIONER JOHNSTON: Or better knowledge. 2 MR. REDMAN: Yes. 3 COMMISSIONER JOHNSTON: Okay. 4 MR. REDMAN: Continuing with the surveillance 5 plans, for offtake management we're going to monitor pressures 6 and for pre-water injection slug sizes, we're going to want to 7 monitor that water injection volume that goes in, and I guess 8 the key here lS is you can't wait for - - if you get water 9 breakthrough, then you've kind of waited too long. We're going 10 to have to be able to make our best estimates of when we get 11 the water banks maybe halfway between injector and producers to 12 get that 20 percent slug in and then start gas injection. 13 On -- in terms of MI breakthrough, weIll look at the · 14 producing wells, GORs, and monitor the MI volumes. There's no 15 other source of free gas really in the reservoir other than the 16 gas that we're injecting or perhaps a little gas from dropping 17 level at the bubble point near producers. So GORs ought to be 18 a pretty clear indicator of when MI is breaking through. 19 COMMISSIONER JOHNSTON: So once you get 20 breakthrough with the MI, what happens then? Do you just cycle 21 MI? 22 MR. REDMAN: You contin- -- yes, you will 23 continue to monitor it. 24 COMMISSIONER JOHNSTON: Right. 25 MR. REDMAN: As you get more and more · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 33 1 breakthrough, you get to a point where you say this pattern is 2 no longer efficient, and you downgrade it or just completely 3 suspend MI into it, put it on chasewater and move the MI 4 somewhere else. 5 COMMISSIONER JOHNSTON: So at the end of the 6 life of the entire EOR process at Alpine, are there any plans 7 to get the enriching components off the Slope? 8 MR. REDMAN: It would depend on in the 9 reservoir runs, we haven't made any kind of attempt to try to 10 blow down the reservoir at the end of 30 years. We've just 11 kind of taken them out there. 12 COMMISSIONER JOHNSTON: Pretty speculative 13 anyway I guess but..... 14 MR. REDMAN: Yeah. That's a long ways out 15 there. 16 COMMISSIONER JOHNSTON: Right. 17 MR. REDMAN: You might be able to get a little 18 out but, you know, there are probably other more lucrative gas 19 targets to go after. 20 COMMISSIONER JOHNSTON: I guess we'll worry 21 about that then. 22 MR. REDMAN: All right. Okay. That concludes 23 the reservoir section. I think now I would like to turn it 24 over to Dr. Fred Stalkup and have him come up and discuss his 25 EOR certification that he's done on Alpine. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . 5 6 7 8 9 10 11 12 13 . 14 . e e 34 1 CHAIRMAN CHRISTENSON: Okay. Thank you. 2 DR. STALKUP: Gentlemen¡ my name is Fred 3 Stalkup. I¡m a consultant representing ARCO. And I would like 4 to give sworn testimony and be considered an expert witness. CHAIRMAN CHRISTENSON: Okay¡ sir. (Oath administered) DR. STALKUP: Yes¡ I do. CHAIRMAN CHRISTENSON: And would you state your qualifications¡ please? DR. STALKUP: Yes¡ sir. I¡m a registered petroleum engineer in Texas. I have 37 years of experience in the petroleum industry¡ all of it with ARCO¡ and much of this experience over my career has been involved in miscible gas flooding technology. I received a Bachelor Degree in Chemical 15 Engineering from Rice University in Houston¡ and a Ph.D. also 16 in Chemical Engineering from Rice in 1961. I authored the 17 Society of Petroleum Engineers monograph on miscible 18 displacement¡ and with ARCO have been involved in numerous 19 miscible project evaluations here in Alaska¡ in the Lower 48¡ 20 in South America¡ and elsewhere. 21 CHAIRMAN CHRISTENSON: And how long -- what 22 have you been doing as far as the Alpine Project? 23 DR. STALKUP: With Alpine? 24 CHAIRMAN CHRISTENSON: Yeah. 25 DR. STALKUP: Well¡ before I left ARCO¡ and I MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 35 1 retired from ARCO at the end of 1998, I had personally done 2 some of the original type model work and was involved with 3 Alpine for about a year, a little better than a year in that 4 regard. In my role as a consultant I have reviewed the Alpine 5 Project with ARCO engineers here in Anchorage and with ARCO 6 personnel at ARCO's technology center in Plano. And in the 7 course of doing that, I reviewed their reservoir engineering 8 studies, their laboratory studies, and their computer modeling 9 studies. 10 COMMISSIONER JOHNSTON: No objection. 11 CHAIRMAN CHRISTENSON: No objection. Consider 12 you an expert witness. 13 DR. STALKUP: Thank you. 14 CHAIRMAN CHRISTENSON: Please proceed. 15 DR. STALKUP: Well, I'm here because I prepared 16 the certification document to certify the Alpine enriched 17 miscible gas project for the EOR tax credit. According to 18 Section 43(c) of the Internal Revenue Code of 1986 and the 19 Treasury Regulations Section 1.43-3, and ARCO Alaska would like 20 to enter this certification document as part of the record of 21 this hearing. And I then would like to verbally summarize some 22 of the conclusions I came to in doing that certification. 23 I believe you're going to enter the document. 24 MR. RODGERS: My name is Dan Rodgers. And Fred 25 asked me to present this. This is six copies of his MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 36 · 1 certification. And we're offering this voluntarily according 2 to Section 05.37(B) of Commission regs. And we ask they be 3 kept confidential because it contains -- some of the exhibits 4 contain proprietary information. Thank you. 5 DR. STALKUP: Thank you. Well, I. . . . . 6 CHAIRMAN CHRISTENSON: Is there going to be 7 testimony with regard to the confidential parts of the.... . 8 DR. STALKUP: No. What I intend to do -- I 9 have no transparencies. And I intend all of my testimony to be 10 verbal and I will not touch on any of the confidential part. 11 CHAIRMAN CHRISTENSON: Okay. 12 DR. STALKUP: I examined the proposed Alpine 13 enriched miscible gas project to determine if it meets the · 14 requirements set forth in treasury regulations for the EOR tax 15 credit, and my opinion is that it does meet these requirements 16 for the following reasons. 17 One, the project involves a qualified tertiary recovery 18 method as defined in these regulations, and this project as 19 you've heard involves the application of the method of miscible 20 gas displacement which is a qualified method. 21 Two, in my opinion, the design and evaluation of the 22 project has been conducted in accordance with sound engineering 23 principles which is another criteria. 24 The application of this project as you've already heard 25 is expected to result in more than an insignificant increase in · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 37 · 1 the amount of crude oil that will be recovered. In fact, it's 2 a very substantial increase in the amount of crude oil that 3 will be recovered. 4 And finally, the project is located in the United 5 States and the date on which first injection of gas will occur 6 is after December 31, 1990, (sic) which is a requirement. 7 Now, in addition to these conclusions which are 8 criteria for certification, I also came to some additional 9 opinions which I would like to discuss briefly and which are 10 also contained in the certification document given to you. 11 One, the installation of facilities to extract the 12 enriching components from the fuel gas permits injection of a 13 gas that's miscible with Alpine oil at the anticipated · 14 reservoir pressure. And because the indigenous enriching 15 components originally come from the oil, they must be captured 16 on site early before the oil rate starts to decline. And for 17 this reason, I think the availability of EaR facilities at 18 field start-up is desirable as ARCO is proposing. 19 Two, the enriched miscible gas project plan of 20 development utilizes the available produced gas much more 21 effectively than the original waterflood plan of development, 22 and it does this by injecting the gas into many wells 23 throughout the field as a WAG slug. It spreads the gas out 24 rather than injecting it continuously into fewer wells in the 25 periphery of the field as was proposed in the original · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 38 · 1 waterflood plan of development. 2 Three, the closer wells facing a 1,500 feet between 3 injector and producer that's being proposed now rather than the 4 3,000 feet between wells as contained in the original plan 5 permits a miscible WAG flood to be economically viable. And 6 the reason for this is that the larger spacing originally 7 proposed on the 3,000 feet with that spacing the production of 8 the incremental oil, the extra oil displaced by the miscible 9 gas is too delayed getting from the injector to the producer to 10 be economical. 11 Three, I don't think it would be sound practice to 12 infill drill from the original 3,000 foot spacing to the 1,500 13 feet at a later date. After a significant amount of water has · 14 been injected on the 3,000 foot spacing, and the reason for 15 this it's already been mentioned is that engineering analyses 16 shows that after water reaches a producing well the 17 productivity of that well and the resulting throughput of 18 fluids through the pattern is severely damaged so you want to 19 drill those 1,500 foot wells now and not infill them and risk 20 drilling them into the water bank. 21 Five, the horizontal injectors and producers in the 22 periphery of the field are necessary to permit a miscible WAG 23 flood there. The vertical wells in the original plan of 24 development would not have a sufficient injectivity to practice 25 the alternate injection of water and gas as opposed to just a · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 6 7 8 9 10 11 12 13 · 14 15 16 17 · e e 39 1 continuous injection of gases as proposed. 2 Sixth¡ the miscible WAG injection must begin early in 3 the field life after no more than approximately two-tenths of 4 the hydrocarbon pore volume of water has been injected into a 5 pattern. As I stated a minute ago¡ engineering analyses shows that if too much water is injected ahead of the miscible gas¡ and this water breaks through into producers¡ the well productivity will be severely damaged before the bulk of the extra oil displaced by the miscible fluids reaches that well¡ and¡ therefore¡ it prolongs the production of that miscible oil¡ and¡ in factI could make it uneconomic to do that. This is a critical consideration. And it¡s unlike most other miscible fluids where the volume of water injected ahead of the miscible gas is not critical or is not as critical as it is. Seven¡ the WAG ratios in this project must be substantially lower than those encountered in most other 18 miscible gas projects. Whereas wide ratios of one to one or 19 higher on 20 projects¡ 21 tenths. a reservoir volume basis are common in miscible the WAG ratio at Alpine probably should be only a few 22 Eight¡ at field start-up¡ produced gas will have to be 23 injected into a few wells without the benefit of prior water 24 injection while the other injectors are receiving their optimum 25 amount of prior water injection. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 40 · 1 Nowl in these patterns it is still desirable later on 2 to catch up on the water injection. So the initial gas 3 injection should go into those patterns that are thought to 4 have sufficient injectivity and productivity that you can 5 inject the desired amount of water during the economic life of 6 that pattern. 7 Andl finallYI conclusion nine is that because the 8 miscible gas solvent is manufactured on site from components 9 originally contained in the reservoir oill there/s a limited 10 supply of it. And for this reasonl the miscible gas fluid 11 can/t be started in all patterns at oncel and as Mr. Redman 12 explained it will require a staged expansion. 13 That/s all I had to say and thank you and lId be happy · 14 to answer questions if you have them. 15 CHAIRMAN CHRISTENSON: Thank you. Davidl do 16 you have any questions? 17 COMMISSIONER JOHNSTON: With the initial gas 18 injection that you pursue before you inject in those few wells 19 before you inject waterl is that going to be an enriched MI 20 or..... 21 22 MI. 23 24 DR. STALKUP: I think it should be an enriched It doesn/t have to be. COMMISSIONER JOHNSTON: Right. DR. STALKUP: But if it IS enrichedl it will be 25 that much more effective in recovering oil so in my mind it · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 41 · 1 would be most desirable to have the EOR facilities ready from 2 the start, the enriching facilities. 3 CHAIRMAN CHRISTENSON: Okay. COMMISSIONER JOHNSTON: Thank you. 4 5 CHAIRMAN CHRISTENSON: Thank you very much. 6 (Off record comments) 7 MR. REDMAN: What I would like to do now is 8 just summarize by going through some suggested findings and 9 recommended conclusions. 10 CHAIRMAN CHRISTENSON: Okay. please proceed. 11 MR. REDMAN: And I'll just read these. First, 12 the recovery process to be used at Alpine is a miscible WAG 13 process using horizontal wellbores. The unit plan of · 14 development is to implement the miscible WAG process across the 15 entire field, and the unit plan plans to begin water injection 16 into most of the injection wells as soon as possible. 17 Simulation studies indicate that the typical injection 18 pattern should receive a volume of roughly 20 percent 19 hydrocarbon pore volume of water before mis- -- implementing 20 miscible gas injection. The unit plans to begin to inject 21 miscible gas into the injection wells in a staged fashion. 22 Several of the injectors will receive gas immediately. Most of 23 the injection wells will receive miscible gas only after they 24 have completed injection of the desired volume of pre-injected 25 water. And the unit expects to begin miscible gas injection · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 11 12 13 · 14 15 16 17 · e e 42 1 into all of the core area wells within seven years of field 2 start-up. 3 Peripheral wells will be drilled four to five years 4 after start-up and all peripheral injectors will initially be 5 on water injection. Because of low permeability in the 6 periphery, the anticipated water injection rates in the 7 periphery are significantly lower than those in the core area. 8 Miscible injectant timing to these patterns will depend on the 9 water injection performance and miscible injectant supplied at 10 that time. The miscible gas will be manufactured by extracting enriching components from the field gas stream and blending those enriching components with the remainder of the produced gas. Laboratory studies indicate that the Alpine produced gas is not miscible with Alpine oil at initial average reservoir conditions of 160 degrees Fahrenheit and 3{200 psi. The produced gas has a minimum miscibility pressure of 18 approximately 3{500 psi. Laboratory studies indicate that the 19 Alpine enriched gas is miscible with Alpine oil at initial 20 average reservoir conditions of 160 degrees Fahrenheit and 21 3{200 psi. The enriched gas has an MMP of 2{900 psi. 22 Since the miscible injectant is manufactured from 23 produced gas, the miscible gas supply is maximized by 24 implementing EOR operations as soon as possible after field 25 start-up. Delaying miscible gas injection will reduce the METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · e e 43 1 volume of miscible gas injection and will consequently reduce 2 ultimate EOR production from the field. Simulation studies 3 indicate that producing well rates will be greatly reduced when 4 water injection reaches production wells. These reduced rates 5 will adversely impact the economics of any subsequent EOR 6 operations. Consequently, EOR operations should be undertaken 7 before injected water reaches the production wells. 8 Those are our findings, and our recommended conclusions 9 are that Alpine is a tertiary enhanced oil recovery. It's 10 using a tertiary enhanced oil recovery method in accordance 11 with sound engineering principles. It's reasonably expected to 12 result in a significant increase in the amount of crude oil 13 that is ultimately recovered, and it must be started early in · 14 the life of the field to maximize ultimate recovery due to productivity impacts of water breakthrough and limited MI 15 16 17 18 19 20 21 22 23 24 25 · supply generated from -- because the MI is generated from oil production. And that concludes my testimony. CHAIRMAN CHRISTENSON: Okay. MR. REDMAN: I'll take any questions. COMMISSIONER JOHNSTON: What was the current reservoir pressure? MR. REDMAN: The initial reservoir pressure is 3,200 pounds. COMMISSIONER JOHNSTON: 3,200 pounds. And your MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 44 . 1 minimum miscibility with your enriched component is 2,900 2 pounds..... 3 MR. REDMAN: Right. 4 COMMISSIONER JOHNSTON: .... .is that right? So 5 In terms of producing the reservoir, you anticipate replacing 6 voidage and maintaining pressure throughout the reservoir? 7 MR. REDMAN: Right. Our simulation studies 8 show that we are able to maintain reservoir pressure above 9 3,000 pounds. Initially, you produ- -- you overproduce a 10 little bit and reservoir pressure drops down under that 3,000 11 pound range and then the water injection catches up. 12 COMMISSIONER JOHNSTON: But we should be 13 keeping an eye on that reservoir pressure and making sure that . 14 it does not drop, and if it does drop to hold that drop to 15 minimum amounts? 16 MR. REDMAN: Right. And if it were to drop, 17 then there's a tradeoff between, you know, taking only part of 18 the stream and making it miscible as opposed to the whole 19 stream and making that stream richer. 20 COMMISSIONER JOHNSTON: Okay. Thank you. CHAIRMAN CHRISTENSON: Okay. Thank you. 21 22 Anybody else? 23 MR. IRELAND: That concludes our testimony 24 today for ARCO as operator in the Alpine Field. 25 COMMISSIONER JOHNSTON: A short break? . MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · 1 2 3 4 5 6 7 8 9 10 11 12 e e 45 CHAIRMAN CHRISTENSON: Yeah, let's go off record and have a short break. (Off record) (On record) COMMISSIONER JOHNSTON: I have a few questions and I suspect maybe Scott might be the best to answer these although if any of the other members feel like they're better to answer the question, then please step up to the mike and go ahead and answer it. I was just curious. You know, the plan that we heard this morning looks to me like it's been well thought out but it also looks like things are being played pretty close to the 13 margins in terms of what you're planning. Everything kind of · 14 has to line out as the theory would have it. For example, the 15 well spacing is 1,500 feet. That's reasonably tight for · 16 horizontals. And, of course, that's -- you hope to do -- to 17 have increased recovery as a result of that spacing but what 18 happens if your fracture system is not quite as you hope it to 19 be, and you have a different orientation on the fracture 20 system, and, in fact, that puts the wells in much more close 21 proximity conductivity-wise than what you currently would 22 anticipate. What's your fall back position? 23 MR. REDMAN: Let me start with saying that we 24 spent some time trying to glve us the best shot at aligning our 25 horizontal wells with the fractures. You know, we looked at METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 46 · 1 where the faults were. We had some core work done to see what 2 was the minimum stress plane so where were we most likely to 3 break the rockl which direction. And we/ve aligned the wells 4 in that direction. Nowl if you get faults going between those 5 long injectors and producers I the favorable mobility ratio that 6 you have I as long as the faults don/t go the full 1/500 feet 7 between injector and producer and are extremely conductive I may 8 actually help you a little bit. You/ll get a little bit more 9 injectivity froml you know I small faultsl or if you getl you 10 knowl a fault in maybe only a few of the wellsl if you get a 11 if there/s a fracture system out there that connected up a 12 whole bunch of those wellsl you know I that/s a reservoir 13 problem that 11m not sure that there/s a good solution for. A · 14 broad fracture system you may not be able to do horizontal 15 wells in another direction either. So it 1 guess 1 would 16 say first that we have attempted to avoid that problem by 17 aligning them where we think the fault -- major faults and 18 fractures are likely to happen I and that the favorable mobility 19 is one of those things that maybe gives us a little more 20 running room that you have in other reservoirs that if you do 21 have a fracture that kind of pushes some water aheadl that 22 water is then at lower mobility relative to the oil that/s 23 being pushed around itl and the -- you can still get good 24 recovery. We did some early sensitivities on putting a 25 fracture that went from an injector to a producerl and it has · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 47 · 1 to have a pretty big perm contrast to keep you from getting the 2 rest of the oil pushed out of the pattern. So in some ways, 3 that's one of the reasons we feel like we can bring these wells 4 this close together and which is needed in order to get the 5 throughput. 6 COMMISSIONER JOHNSTON: In terms of the 7 availability of MI, I assume that based upon the what I saw 8 this morning that you're planning on constructing a MI that had 9 a miscibility pressure of -- a minimum miscibility pressure of 10 2,900 pounds, I mean that seems like your optimum amount based 11 upon what you're producing and your facilities that you have 12 and this sort of thing. What -- in terms of the total volume 13 of MI that you're going to be able to make expressed in · 14 hydrocarbon pore volume, how much MI will you be able to 15 construct out there? 16 MR. REDMAN: Over the life of the field based 17 on that forecast you can get 20 to 30 percent hydrocarbon slugs 18 into -- on -- into the whole field on that basis. Part of that 19 is recycle as, you know, some of it is the actual material that 20 is coming out of the ground, and some of that is once you get 21 the MI and you reinject it, some of it will eventually be 22 reproduced again at the producers and it circulates around. 23 COMMISSIONER JOHNSTON: So it's your opinion 24 then that you will have adequate supply at Alpine, an adequate 25 supply of MI at the enriching level that you anticipate? You · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 48 · 1 don't see any need potentially to bring in additional MI into 2 the field? 3 MR. REDMAN: I think that we would continue to 4 test whether or not there is a source out there to bring in. I 5 think for the core area we probably are fine. If you notice 6 those MI -- that MI plot that I showed MI rates kind of 7 dropping out in the -- kind of the 20 to 25 year time frame. 8 That's kind of the time frame you would really like to have 9 some more MI if it was available, and the -- if you get better 10 pr- -- if you produce more oil from the field, you're going to 11 get more gas. That would be a source that would help you. 12 Another would be if we find satellites around Alpine and we put 13 them on waterflood and bring those components back into Alpine. · 14 That increases our supply. The field also does pretty well on 15 lean gas chase. So somewhere down the road we probably 16 wouldn't rule out bringing in maybe, you know, some source 17 from, you know, Kuparuk or somewhere else to follow the MI slug 18 we put in with lien gas. 19 COMMISSIONER JOHNSTON: What happens in the 20 event that things perform better than anticipated? Are you 21 going to be limited -- MI limited in terms of the amount of MI 22 that you can build at anyone time in terms of getting it in 23 getting the amount into the reservoir that you would want in 24 the optimum locations? 25 MR. REDMAN: Are you going to be limited. I · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · · · e e 49 1 guess if you had very high production rates you might get to 2 the point where you couldn't make the whole stream miscible and 3 you might have to break it off into part of the stream 4 immiscible, part of the stream miscible. And are you limited. 5 I mean I think over the life of the field you'll still get the 6 good slug sizes, and, if anything, you know, better performance 7 early is going to net you more oil which is going to net you 8 more MI volume over the life of the field. It may cause you 9 some operational problems early in the life of the field to 10 kind of split the stream between immiscible and miscible 11 sections. 12 COMMISSIONER JOHNSTON: Yeah. I guess what I'm 13 trying to get at is just a better understanding of your options 14 that you've considered in all these different scenarios. I 15 mean do you have enough MI available in the reservoir? Do you 16 have enough MI today? Are your rates sensitive toward building 17 this? What are your options if you are rate sensitive? And do 18 you have plans or is it feasible to bring in additional MI if 19 you need it? 20 MR. REDMAN: You really need to come up with 21 that incremental MI source that makes economic sense. And 22 the -- kind of the main hurdle that you have is, one, you're 23 probably going to have to build another 30 plus mile pipeline 24 to Kuparuk and maybe even farther than that. Maybe you have to 25 go all the way to Prudhoe to get a gas source plus the capital METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 50 · 1 cost. And that weighed against the kind of that incremental of 2 putting in a 20 percent slug versus a 25 percent slug or a 30 3 percent, you can see that there are diminishing benefits for 4 the flood. So if you can get out to those, say, call it 20 5 percent slug sizes without that, you're going to have a tough 6 time economically justifying it based on Alpine alone. Now, 7 you may bring it up. You know, you may have other satellites 8 around there that justify it and then you have it available. 9 COMMISSIONER JOHNSTON: So..... 10 MR. REDMAN: But as a stand alone -- we have 11 looked at bringing just straight gas into the field as a 12 development plan, and that was not as good as either the 13 waterflood option or the MI options. · 14 COMMISSIONER JOHNSTON: So then if I heard you 15 correctly, then if MI -- if the availability of MI ever became 16 a critical aspect of this reservoir, then some of your options 17 that you would have available to you would be to lower the 18 overall amount of slug size dropping down maybe from a 30 19 percent pore volume to 25, 22, down..... 20 MR. REDMAN: Right. 21 COMMISSIONER JOHNSTON: .... .to 20. And I 22 would also guess that you have some flexibility built in with 23 the -- into the process on how rich you make your MI. 24 MR. REDMAN: Yes. 25 COMMISSIONER JOHNSTON: You can make a little · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e e 51 · 1 bit leaner MI and make more of it, right? 2 MR. REDMAN: You can but we would -- I think we 3 would like to stay above a minimum miscibility pressure at, you 4 know, average reservoir conditions. So we would -- if we had 5 to make a choice, we would probably choose to continue to make 6 MI, make it rich enough, but you might end up with a secondary 7 stream of lean gas that you would take an area of the field and 8 only put lean gas into. 9 COMMISSIONER JOHNSTON: Right. Okay. Thank 10 you. No further questions. 11 CHAIRMAN CHRISTENSON: I have no further 12 questions so do you have any more testimony that you would like 13 to present for the Commission? · 14 MR. IRELAND: No, I think we're complete. 15 CHAIRMAN CHRISTENSON: Okay. We would like to 16 thank you very much for your presentation and, therefore, we 17 are adjourned. 18 (Off record 10:50 a.m. ) 19 END OF PROCEEDINGS 20 21 22 23 24 25 · METRO COURT REPORTING, I NC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 e . 52 . 1 C E R T I FIe ATE 2 UNITED STATES OF AMERICA) ) ss. 3 STATE OF ALASKA ) 4 5 6 7 8 9 10 11 12 13 . 14 . 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 Commission Public Hearing was taken before myself on the 19th day of October 1999¡ commencing at the hour of 9:05 o¡clock a.m.¡ at the offices of Alaska Oil & Gas Conservation Commission¡ 3001 Porcupine Streett 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 15 affixed my seal this 5th day of November 1999. NO~i~laSka My commission expires: 05/03/01 16 17 18 19 20 21 22 23 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 #6 · , ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING October 19, 1999 9:00 AM NAME - AFFILIATION (pLEASE PRINT) M()j'-J& Trr~~£ L),':J ~D¿j( S;-Ov f:./ K~d~l1l... '{y\\\u SrvJliY' .JftJ2.J ~ ~+- M<Gu.I~ .bjO '^-J ~ -lsfttv- ¡hulk 5MbBJ <; Gr~ r'i hr-,,) ~'" -flL GsVI /ff /;i4¡;;- ~ ~y/~ ~¡'~I/e... ~vie5 ~tf L-.~.L,// Colville River Unit Area Injection Order DO YOU PLAN TO TELEPHONE TESTIFY? Yes No !ifaJ ~3-+7~7 II II 2..('S- CJo6 :JeJ Mc:o Z,,~- é¡~/C¡ ~ÇS fJr;(A) a.(oS' - \,-\- ì e ~ C.v'\~ 1ì1--1-Y; -ej'5ìt1 °1 ~5 Af..Lò 2.1..';- 6<"'-17 no Jt~~ ..,7(p} -c./7~ø? NfJ ;.!.N4.tJM lCð ~fo~ r- t9'1 r ç AJo ~&G.'\.t<o _"i]- '1'178 N0. ~ z.~S"- ns"y }JCJ ~/f?4?7l/e /fC/Rrt ';-6/-/'/rrs-- Pc> Aa;cc 793- /221 ~ AoC: <::<:'. ?/~-/2..Jd AJd ôe$ #5 ARCO Alaska, Inc. . Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . ~~ ~~ October 19, 1999 Mr. Bob Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Area Injection Order Alpine Oil Pool Colville River Unit Dear Chairman Christenson: ARCO Alaska, Inc. (ARCO), as an owner and the operator ofthe Colville River Unit, seeks Alaska Oil and Gas Conservation Commission (Commission) endorsement and authorization to conduct a Miscible Water-Alternating-Gas Project in the Alpine Oil Pool. Enclosed is the application for this project prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). Attached are six copies of the application package, which includes the proposed rules, supporting pre-filed testimony, and exhibits. These copies supercede the draft copies previously provided to the Commission by letter dated September 3, 1999. For additional information supporting either application, please contact R. Scott Redman at 263-4514. Sincerely, ßk-i/~~0 ¡¿~ Mark M. Ireland Alpine Development Manager RECEIVED OCT 19 1999 AIaka on & Gas Cons. Commission '. Anchorage ARca . . cc: Mr. Kenneth A. Boyd, Director Alaska Department of Natural Resources Division of Oil & Gas 3601 C Street, Suite 1380 Anchorage, Alaska 99503-5948 Ms. Teresa lmm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 Mr. Isaac Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 Mr. Jerry Windlinger Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Todd Liebel Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 . . Alpine Area Injection Order ARCO Alaska, Ine Anadarko Petroleum Corporation Union Texas Petroleum, LLC October 19, 1999 e . Table of Contents Reference Subject Pa2e Introduction 4 20 AAC 25A02(c)(1) Plat of Wells Penetrating Injection Zone 5 20 AAC 25A02(c)(2) Operators and Surface Owners 6 20 AAC 25A02(c)(3) Notice to Surface Owners (See Exhibit 2) 20 AAC 25A02(c)(4) Description ofthe Proposed Operation 7 20 AAC 25 A02( c)( 5) Description and Depth of Pool to be Affected 11 20 AAC 25A02(c)(6) Description of the Formation 13 20 AAC 25 A02( c )(7) Type Log (see Exhibit 13) 20 AAC 25A02(c)(8) Casing Description 14 20 AAC 25A02(c)(9) Injected Fluid Analysis 16 20 AAC 25A02(c)(10) Estimated Pressures 17 20 AAC 25A02(c)(11) Fracture Information 18 20 AAC 25A02(c)(12) Formation Fluid 20 20 AAC 25A02(c)(13) Aquifer Exemption 24 20 AAC 25A02(c)(14) Incremental Hydrocarbon Recovery 25 Recommended Conclusions 27 Requested Decisions 28 2 Exhibit 1 Exhibit 2 Exhibit 3 Exhibit 4 Exhibit 5 Exhibit 6 Exhibit 7 Exhibit 8 Exhibit 9 Exhibit 10 Exhibit 11 Exhibit 12 Exhibit 13 Exhibit 14 Exhibit 15 Exhibit 16 Exhibit 17 Exhibit 18 Exhibit 19 Exhibit 20 Exhibit 21 Exhibit 22 . . List of Exhibits Proposed Alpine Development Wells Affidavit of Notice to Surface Owners Miscible WAG and Waterflood Oil Recovery Effect of Enrichment on WAG Recovery Impact of Water Breakthrough on Production Rates Impact of Pre-water Injection on Miscible WAG Recovery Impact ofW AG Injection on Water Injection Rates Impact ofMiscible Injectant Slug Size on WAG Recovery Alpine Facility Schematic Miscible Injectant Supply Forecast Core and Peripheral Development Areas Alpine Oil Pool Section Boundaries Bergschrund 1 Type Log Top Alpine Depth Structure Map Alpine Oil Pool Type Log Injector Completion Schematic Lean Slimtube Data Rich Slimtube Data MME Plot of Enriching Fluid Fraction versus Pressure Elastic Properties and Strength from Laboratory Tests Bergschrund No. 1 Minimum Horizontal Stress Log StimPlan Fracture Height Growth Model 3 e . Alpine Area Injection Order Introduction This application seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed Alpine Miscible Water Alternating Gas Project. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). On December 3, 1998, the Commission held an Alpine Pool Rules Hearing. This hearing reviewed pool rules and injection disposal without considering enhanced recovery operations. On March 15, 1999, the Commission issued Conservation Order #443 establishing Alpine Oil Pool Rules for development. In the Alpine Pool Rules Hearing, ARCO presented the original plan of development as well as a potential new plan of development. Since the Pool Rules hearing, the Alpine Working Interest Owners have obtained funding approval for a new pIan of development and are working to obtain approval ofthe lessors. A description ofthe original and new plans of development are provided below: Original Plan of Development The scope ofthe original development included horizontal wells in the center of the field and vertical wells around the periphery. Horizontal wells were drilled on 275-acre spacing and the vertical wells were on 160-acre spacing. The original recovery process was waterflood in the center of the field with gas re-injection around the periphery. The original development was estimated to recover 38% OOIP. New Plan of Development The new development includes only horizontal wells on 135-acre spacing (see Exhibit 1). A Miscible Water-Alternating-Gas (MWAG) process is implemented at startup. The miscible injectant is made from solution gas enriched with C2+ components recovered from the fuel gas. The proposed development is estimated to recover 45% OOIP. 4 e . Alpine Area Injection Order 20 AAc 25.402 (c)(1) Plat of Wells Penetrating Injection Zone The attached map (Exhibit 1) shows all existing wells penetrating the injection zone in the proposed injection area. The map also shows the areal extent of the injection zone relative to the Colville River Unit boundary, and the 10cation of all proposed Alpine Oil Pool development wells. 5 e Alpine Area Injection Order 20 AAC 25.402 (c)(2) e Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: Surface Owners: ARCO Alaska, Inc. Attention: Mark Ireland P. O. Box 100360 Anchorage, AK 99510-0360 State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Isaac Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 6 e e Alpine Area Injection Order 20 AAC 25.402 (c)(4) Description of the Proposed Operation An Area Injection Order is needed to develop the Alpine Reservoir. The expected scope of the current development project involves drilling approximately 112 wells to develop 429 MMBO associated with an estimated 960 MMBO original oil in place (OOIP). Field Development Development wells will be drilled from two drill sites. Field development includes only horizontal wells on 135-acre spacing. Well layout is a direct line drive pattern configuration with rows of injectors and producers spaced 1500' apart. The wells have horizontal sections of 3000' with 1000' lateral displacement between wells along each row. Recovery Mechanism Alpine has a favorable water-oil mobility ratio that results in high areal and vertical sweep efficiency for waterflooding. Core flood studies indicate the waterflood process will leave behind high residual oil saturations in the range of 35-40%. The high residual saturations left behind by the waterflood provide an excellent tertiary recovery target. Fine grid, compositional reservoir simulations indicate that MW AG increases ultimate recovery by 10-12% at the pattern level (see Exhibit 3). This high incremental MW AG recovery is achieved by reducing oil saturations in the gas swept areas and by swelling residual oil in the miscible displacement process. Miscible Injectant Supply Produced gas from the Alpine Oil Pool is the only viable source of enriching components for MW AG. No other current sources of enriching components could be economically procured and transported to the field. Raw separator gas is not miscible with Alpine crude oil at the average reservoir pressure. However, the mixture of raw separator gas with enriching components from the fuel gas is sufficient to attain miscibility. Production priorities for the plant are to (1) maximize saleable oil production, and (2) maximize the recovery of enriching components from the fuel gas system to produce an enriched miscible injectant stream that is above the Minimum Miscibility Pressure (MMP) at average reservoir pressure. The benefit of miscible injectant enrichment on WAG recovery is shown in Exhibit 4. In this plot, "Klean" is Kuparuk lean gas without enriching components, "lean gas" is Alpine produced gas without any enriching components, "tail gas" is Alpine produced gas enriched only with components available from the original facility design, and "MI" represents the Alpine produced gas stream fully enriched by the enhanced facilities currently proposed for MW AG. The trend line 7 e e represents the impact of increasing enrichment on oil recovery. As shown, incremental recovery increases as the fraction of C2+ in the gas increases. EOR facilities installed to increase miscible injectant volumes also increase saleable oil production by 500-1000 STB/Day. The additional LP aftercooler and associated piping modifications enhance condensate recovery from the LP gas stream. EOR Project at Field Startup In typical miscible water-alternating-gas (MW AG) projects, the timing ofMW AG startup in relation to waterflood is not critical. However, at Alpine it is very important to begin the EOR project early in the producing field life. Otherwise, the EOR reserves ofthe project could be significantly reduced. Exhibit 5 is a plot of water and oil rates versus time and hydrocarbon pore volume injection (HCPVi) for a single waterflood pattern. This plot predicts reduced injectivity and productivity after water breakthrough. Model studies predict a significant reduction in incremental recovery ifMW AG injection is begun after water breakthrough. Proper staging of the EOR project Studies to determine the optimum development strategy for this reservoir have been undertaken. Laboratory studies of the reservoir fluids, rock properties and potential injection fluids have been consolidated in compositional reservoir simulations to understand the most efficient recovery process. These simulations indicated that in the low and modest permeability portions ofthe reservoir there is a clear optimum volume of water that should be injected before commencing MW AG operations. Exhibit 6 shows undiscounted and discounted incremental recovery versus water pre-injection slug size for several miscible injectant slug sizes. As shown, the optimal water injection volume prior to initiating miscible WAG injection is about 20% of the pattern's hydrocarbon pore volume. If solvent injection is begun after excessive water injection, the injected water could reach production wells before EOR oil can be produced. Once this occurs, adverse relative permeability will cause a substantial reduction in production rates, and EOR oil could be produced very slowly. This is expected to greatly impact the ultimate economic oil recovery of the EOR project. Conversely, once solvent injection is begun as part of the MW AG process, the adverse relative permeability of water in the presence of gas could lead to 10w water injection rates (see Exhibit 7). If solvent injection is started too early, it may not be possible to inject the desired volume of water during the economic lifetime of the pattern, negatively impacting ultimate oil recovery. Surveillance Plans Surveillance plans for Alpine include monitoring reservoir pressure, running spinners in the injectors and producers to monitor fluid profiles, and voidage balancing to minimize pattern skew. In addition, surveillance for the Miscible WAG development plan will include monitoring injection rates and compositions, monitoring GOR and WOR to identify gas and water breakthrough, monitoring the water pre-injection slug sizes and the 8 e e miscible injectant slug sizes, and monitoring the overall pattern performance to trigger miscible WAG pattern expansion. Injectivity Issues Lower permeability rock, such as that found in the periphery ofthe Alpine pool, will show a significant reduction in relative permeability to water after the first slug of gas is injected. This may create problems providing adequate pressure support to the offsetting producers after miscible gas injection is initiated. Simulation work indicates that the optimum hydrocarbon pore volume of water to inject prior to the first slug of miscible gas to be 20%. If too little water is injected prior to the first miscible gas it could reduce the sweep efficiency of the miscible flood and potentially reduce ultimate recovery from the field. If too much water is injected prior to the first miscible gas the 10wered relative permeability slows oil recovery thereby reducing ultimate recovery from the field. Adequate injection to withdrawal rates can be maintained by increasing the amount of gas injected during the MW AG cycle in those areas most affected by the relative permeability reductions. In the higher permeabilty areas of the reservoir the MW AG process will reduce the injectivity less. It is these areas which can be targeted for miscible gas injection early. Exhibit 8 shows incremental oil recovery vs MI slug size in a Stillstand type pattern model. The first 15-20% MI slug size is very efficient. MI slug sizes larger than 30% HCPV have diminishing benefits. Models suggest the patterns should typically reach total 'water plus gas' slug size of approximately 0.8 HPV (hydrocarbon pore volume) of injection by the end of field life. Solvent Supply A schematic ofthe Alpine process equipment is shown in Exhibit 9. The facilities added for the EOR project are shown in red. There is a Joule-Thompson (JT) fuel gas unit, a new LP aftercooler, and piping modifications to re-route the LP stream to the condensate flash drum to recover condensate liquids from the gas. A forecast of the miscible injectant rates versus time is shown in Exhibit 10. There is a potential shortage ofmiscible injectant late in the field life. The Alpine miscible injectant supply could be enhanced with better than expected field performance or importing gas from satellite fields, assuming such sources become available. Solvent supply is derived solely from produced gas. Consequently, insufficient solvent is available to start WAG in all patterns at once, even if that were desirable. Given this solvent supply constraint along with the need for injecting a water pad in the modest and low permeability patterns, a staged EOR expansion schedule is critical. The flood will initially start up with several wells on gas injection and the remaining injectors taking seawater. The core and peripheral areas of the Alpine Field are shown in 9 e e Exhibit 11. As the higher permeability patterns in the core area reach their water injection targets, they will be converted to MW AG injection. It is expected to take about 2 to 4 years for the first 20 wells. Subsequently, as the lower permeability patterns in the core area reach their water injection targets, they will be converted to MW AG injection. It is expected to take about 5 to 7 years for the final 20 wells in the core area. All patterns continue on MW AG until reaching a target MI slug size or surveillance data indicates a pattern is no longer competive. Peripheral wells will be drilled 4 to 5 years after startup and all will initially be on water injection. Miscible injectant timing in these patterns will depend on water injection performance and miscible injection supply. Disposal Operations Class 1 disposal operations have been authorized by EP A Region 10 under Permit Number AK.-1I003-A effective February 3, 1999. All injected fluids will be confined to the Ivishak Sandstone ofthe Sadlerochit Group. This interval is wet in this region ofthe North Slope. 10 e e Alpine Area Injection Order 20 AAc 25.402 (c)(5) Description and Depth of Pool to be Affected Location The Alpine Oil Pool is located approximately 20 miles west of the Kuparuk River Unit in the Colville River delta area on Alaska's North Slope. Exhibit 1 shows the approximate outline ofthe pool east ofthe National Petroleum Reserve - Alaska (NPRA). The Colville River Unit boundary and sections subject to the Alpine Oil Pool rules are shown in Exhibit 12. The rules hereinafter set forth apply to the following described area and are referred to in the order as the affected area: Umiat Meridian T11N, R4E Sections 1-5 all, 7-16 all, 21-27 all. T11N, R5E Sections 1-24 all, 29-30 all. T12N, R4E Section 24,25-27,33-36 all. T12N, R5E Sections 13-15 all, 19-36 all. Age of Sediments Based on ARCO in-house palynology and micropalentology the Alpine interval is considered to be Late Jurassic in age. Pool Name The name Alpine was first applied to a Late Jurassic prospect developed by ARCO in the Colville Delta area. In 1994, the Bergschrund 1 discovery well was drilled and subsequently ARCO has used the informal name Alpine to describe the oil-bearing upper most Jurassic sandstone body. The Alpine Oil Pool is the hydrocarbon-bearing interval between 6,876 and 6,976 feet measured depth in the Bergschrund 1 well (Exhibit 13) and its lateral equivalents. The Top Alpine and Kingak E 10g markers bound the interval. The Top Alpine marker is defined by the minimum value on the deep resistivity curve below the Miluveach Shale. The Kingak E marker is a deep resistivity inflection point near the top of a coarsening- upward sequence in the Kingak Formation. Several Kingak markers are correlatable across the Colville River Unit. 11 e e Trap and Structure Well results and seismic data suggest the Alpine reservoir is a stratigraphic trap in which the Alpine sandstones are isolated within marine shales ofthe Kingak and Miluveach formations. Hydrocarbon accumulation is controlled by the distribution of reservoir quality sandstones. No water or gas cap has been encountered to date in the Alpine interval. Exhibit 14 is a top Alpine depth structure map based on 3D seismic data. Structural dip is to the southwest at 1 to 2 degrees. The major faults in the Alpine Oil Pool area are normal north-northwest trending, and down thrown to the west. At the Alpine level, most of the faults have small throws, generally less than 25 feet. 12 e e Alpine Area Injection Order 20 AAC 25.402 (c)(6) Description of the Formation Stratigraphy In the Colville River Delta area, the Kingak Formation contains at least three oil-bearing Upper Jurassic sandstone bodies informally named Alpine, Nuiqsut, and Nechelik (Exhibit 15). The uppermost Alpine sandstone displays the best reservoir properties of the three. The Jurassic sands were derived from a source area to the north and deposited on a shallow marine shelf in the present Colville Delta area. Each of these sandstone bodies is associated with an overall coarsening upward sequence that ranges from 200 to 300 feet thick. Each sand top is fairly sharp, suggesting rapid burial by marine mudstones of the Kingak and Miluveach intervals. Bergschrund 1, drilled in 1994, penetrated 48 feet of oil-bearing Alpine sandstone. The Alpine sandstone tested 2,380 BOPD of 40 degree API gravity oil. The Alpine sandstone consists of very fine to fine-grained, moderate to well sorted, burrowed, quartzose sandstone with variable glauconite and clay content (Exhibit 15). Core porosity and permeability ranges are, respectively, from 15% to 23% and 1 to 160 millidarcies. The best quality sandstones are coarser grained with low matrix content. In the proposed development area, the reservoir sand body is east-west elongate, roughly 8 miles 10ng by 3 miles wide. The sand body is continuous across the development area with shale and nonpay facies only rarely present. Sand thickness from well data ranges from 30 to 110 feet. 13 - e Alpine Area Injection Order 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing Casing Drilling/W ell Design All underground injection into the Alpine Oil Pool will be through wells permitted as service wells for injection in conformance with 20 AAC 25.005, or approved for conversion to service wells for injection in conformance with 20 AAC 25.280. Additionally, all injection wells will be constructed in accordance with 20 AAC 25.030, 20 AAC 25.412, and Conservation Order 443 (Colville River Field, Alpine Oil Pool). A typical wellbore schematic is included as Exhibit 16. The Alpine Oil Pool will be accessed from wells directionally drilled from one of two gravel pads utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. The following will preview an Alpine drilling proposal for both producing and injection wells. For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Surface holes will be drilled to a minimum of 1500' TVDSS for proper anchorage, prevention of uncontrolled flow, protection of aquifers, and protection from permafrost thaw and freeze back. This casing setting depth provides sufficient depth for kick tolerance, yet shallow enough to initiate build sections for high departure wells. Either 9- 5/8" or 7" surface casing strings are cemented to surface using lead slurry of lightweight permafrost cement, followed by tail slurry in a single stage. No hydrocarbon bearing intervals have been encountered to this depth in previous wells. The casing head and blowout preventer stack will be installed and tested consistent with Commission requirements. A Leak-Off Test (LOT) will be performed upon drilling no more than 50' beyond the surface casing shoe in accordance with 20 AAC 25.030(d)(2)(D). Production holes will be drilled from surface casing, encountering the top of the Alpine at typically 50-70 degree inclination. Production casing will be set close to horizontal and cemented within the Alpine sands. Production casing will vary in size from 7" to 3-1/2" OD. Top of cement will extend a minimum of 500 feet measured depth above the Alpine sands in accordance with 20 AAC 25.030(d)(4)(B). After drilling out the production casing, and prior to drilling 50' ahead into the Alpine formation, a Formation Integrity Test (FIT) will be performed (in accordance with Conservation Order No. 443 Rule 4.a) to a predetermined equivalent mud weight (EMW). Note that the Alpine reservoir fracture gradient (20 AAC 25.030(d)(2)(D» will 14 e e not be reached to minimize formation damage. Production hole will be drilled beyond the casing shoe horizontally in the Alpine sand. Lengths achieved will vary from 500' up to perhaps 8,000 ft. depending on reservoir characteristics and specific wellbore geometry. Production liners in specific cases will be required, but it is anticipated that the majority will be completed openhole. Uncemented slotted liners are included in the drilling plans on an "as-needed" basis. For example, wellbores that encounter significant shale or 10st circulation intervals may receive slotted liners with external casing packers (ECP). At some point in the future coil tubing workovers may place slotted or cemented liners within the Alpine sands. Should any wells be drilled where production casing is set below rather than within the Alpine sands, production casing will be cemented across and not less than 500 feet measured depth above the Alpine. An example would be any extended reach S-shaped wells that encounter Alpine sands at inclinations below 60 degrees In addition to conventional open hole and perforated completions, additional completion designs may be presented for administrative approval by submitting and presenting data demonstrating that such alternatives are based on sound engineering principles. Casing Testing Casing-tubing annulus pressures will be monitored during injection operations in accordance with 20 AAC 25.402(d & e). Injection rates, tubing and casing pressures will be recorded on a daily basis, and abnormalities will be noted and evaluated. Significant deviations or aberrations in pressures or rates will be communicated to the Commission. Trained and qualified operators will be inspecting the wellheads and gauges as part of their daily routine. Prior to commencement of injection, each injection well will be pressure tested in accordance with 20 AAC 25.412(c). On a frequency not to exceed every 4 years, the mechanical integrity of each well will be verified in accordance with 20 AAC 25.412. In all cases, the Commission will be notified at least 24 hours in advance to enable a representative to witness the testing. In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, Arco will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Abandonment All abandonment procedures will be performed following Commission approval in accordance with 20 AAC 25.105. 15 · e Alpine Area Injection Order 20 AAC 25.402 (c)(9) Injected Fluid Analysis Two series of slimtube laboratory experiments have been performed on Alpine crude oil. The first series of experiments indicated that the produced gas was not miscible with Alpine oil at initial average reservoir conditions of 160 degrees F and 3200 psi. The MMP ofthe produced gas was 3500 psi (Exhibit 17). The enriched gas for the second series of slimtube experiments was fully miscible with Alpine oil at initial reservoir conditions. The MMP for this gas was 2000 psi (Exhibit 18). The Alpine Equation of State predicted these two experiments. The EOS was then used to develop a correlation that predicts the amount of enriching material that must be blended with Alpine lean gas to achieve miscibility at a given pressure (Exhibit 19). Miscible Injectant will be manufactured at the Alpine CPF by blending enriching fluids extracted from the fuel gas into Alpine produced gas. The initial composition of the MI will be controlled to a minimum C2+ content to assure miscibility with the oil. The expected MI composition is shown below: Component MI N2 0.0048 CO2 0.0055 C1 0.6450 C2 0.1200 C3 0.1446 C4 0.0670 C5 0.0101 C6 0.0021 C7-8 0.0009 Total 1.0000 Initially, Beaufort Sea water will be injected in the field with MI. Seawater has been tested and found to be compatible with the Alpine formation. Later in the field life, after water breakthrough occurs, Alpine produced water will also be re-injected in the formation. Prior to injecting produced water into the field, testing will verify that the produced fluids are compatible with the Alpine formation. 16 e e Alpine Area Injection Order 20 AAC 25.402 (c)(lO) Estimated Pressures The maximum MI injection pressures available at the plant will be 4500 psi. 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. Wellhead injection pressures are expected to range from 3600 psi to 4300 psi. The maximum seawater injection pressures from the plant pump discharge are expected to exceed 2500 psi. Assuming cold injection temperatures and anticipated injection rates, wellhead pressures are expected to hover around 1800 psi. 17 e e Alpine Area Injection Order 20 AAC 25.402 (c)(ll) Fracture Information The State of Alaska has determined there are no fresh water aquifers within the Colville River Unit. Consequently, injected fluids cannot breach the Alpine Oil Pool and threaten local fresh water sources. Additionally, rock mechanics studies suggest injected fluids will be wholly contained within the Alpine Oil Pool. Sufficient fluid samples and log derived formation water salinities have been presented to the State of Alaska and the federal Environmental Protection Agency (EP A) to determine there are no Underground Sources of Drinking Water (USDW) in the Colville River Unit. Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Permit Application, Appendix D, previously submitted to the Commission in September 1997. Rock mechanics and fracture analysis confirm that although bottom-hole injection pressures will routinely exceed the formation parting pressure, all injected fluids will remain contained within the Alpine Oil Pool. This conclusion is supported by core studies directed by Arco Exploration and Production Technology (AEPT) as well as dipole sonic data from offset wells. In December 1997, Rico Ramos of AEPT published the results from his laboratory investigation of the mechanical properties of Alpine #1 and Neve #1 cores. The results are included as Exhibit 20. Cores from the shales immediately above the Alpine were found to be softer and therefore less prone to fracture than the more brittle Alpine cores. The lab-derived average Poisson's Ratio of 0.33 in the upper bounding shale and 0.22- 0.23 in the sands compares favorably with log derived values of Poisson's Ratio. Using dipole sonic log data gathered in the Bergschrund #1, a log of minimum horizontal stress, or fracture pressure, has been plotted with pore pressure and is attached as Exhibit 21. This 10g confirms the favorable stress contrast between the Alpine sand and its bounding shales. The Miluveach formation sits atop the Alpine Oil Pool, providing an approximately 120' upper boundary to fracture growth. This competent shale's minimum horizontal stress is 600 to 700 psi higher than the Alpine fracture pressure, providing an excellent stress contrast. The Upper Kingak formation provides the fluid seal immediately below the base of the Alpine reservoir. This laterally extensive shale averages approximately 150' thick within the productive Alpine Oil Pool limits. The Upper Kingak is mainly composed of dense clay-rich siltstone. Log analysis confirms this shale provides a minimum stress contrast of 700-800 psi relative to the Alpine fracture pressure. 18 e e The Alpine Oil Pool fracture gradient has been determined to be 0.60 psi/ft. This was observed during a data frac performed on Alpine #IB preceding a fracture treatment in 1996. The surface measured Instantaneous Shut-In Pressure (ISIP) was 1750 psi with diesel displaced to the perfs. A confirming fracture gradient was observed during oil re- injection operations upon the conclusion oftesting CD2-35. Pressure measurements taken with gauges installed immediately above the packer measured an initial fracture extension pressure of 4200 psi, or 0.6 psi/ft. This data closely matches lab and log predicted fracture pressures. Fracture modeling using Stimplan (i.e., Nolte/Smith's pseudo 3-D fracture model) confirms fracture heights are established very early in the operation and remain entirely contained within the Alpine. Model runs in a 39'thick Alpine interval with sand and shale rock properties taken from 10g and lab data assuming injection for approximately 2 years at water injection rates of 10 bpm project gross fracture height to reach 50 feet. Such a fracture would only breach 11' beyond the Alpine formation. This estimate is conservative since projected injection rates will not exceed 5 bpm. Under comparable constraints the same models predicts 5 bpm generated height growth to reach 45', or 6' into adjacent shales (see Exhibit 22). This estimate will be conservative for injection of gas or MI. Such compressible, low viscosity fluids will generate significantly less fracture growth. Conservative current models such as Stimplan assume 'worst case' single, planar, vertical fractures that result from relatively short duration injection (approximately 200,000,000 gal.). These models were developed for short duration fractures into less ductile, brittle "hard rock" formations. Since dendritic fractures, disaggregation (i.e., destruction of the rock matrix) and particle invasion ofthe rock matrix are not captured by these models, they conservatively represent the impacts of years oflong term injection adjacent to "soft" shaley formations. Including the effects of dendritic fractures, etc. increases fluid storage thereby reducing height and length projections. 19 e e Alpine Area Injection Order 20 AAC 25.402 (c)(12) Formation Fluid Salinity Calculations In the Alpine project area only the Nechelik #1 well has been 10gged from surface through the injection zone. No clean sands were encountered above the confining zone; however, the Alpine #1 well did cut some thin Albian sands at 5150-5204 feet, and Bergschrund #1 found a thin shelf sand at 4220 feet. Salinity calculations made on available intervals resulted in the following. · Bergschrund # 1 (4220 feet) 15,000 ppm NaCl eq. · Alpine # 1 (5150-5204 feet) 15,000 ppm NaCl eq. · Nechelik #1 (Sag River Formation) 18,000 ppm NaCl eq. · Nechelik #1 (Ivishak Formation) 17,000 ppm NaCl eq. The methodology used and results obtained from salinity calculations on the AlbianlNanushuk Shelfsand stringers (Alpine #1 and Bergschrund #1), Sag River, and Ivishak Formations (Nechelik #1 well) are as follows. The calculations use the standard Archie correlation and log derived data to obtain an Rwa value using the following formula: Rwa = (porosity) ill (Rt) / a ........... with the following definitions: Rwa Porosity Rt Resistivity of water necessary to make a zone 100 % wet Porosity in decimal from logs Formation resistivity from logs Cementation exponent Assumed to be 1.0 per the Archie correlation m a The cementation exponent is the variable ofleast certainty. The best source for determining this value is from special core analysis (SCAL) when available. No SCAL is available for the Albian interval; however, such data does exist for analogous fine to very fine grain sand in the area. This data has yielded: Alpine section SCAL from the Alpine #1 well m = 1.55 20 e e Sag River SCAL as documented in ARCO TSR 95-46, internal report m = 1.6 The following exponents will be used in these salinity calculations. Shallow intervals (4000- 5000 feet) Sag River Formation Ivishak Formation m = 1.6 m = 1.7 m = 1.8 · Nanushuk ShelfSand: (Bergschrund #1 well depth 4220 feet) This shelf sand is evident in two wells at approximately 4200 feet subsea. Rt = 4.0, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The calculation yields an Rwa equal to 0.356. Using Schlumberger Chart Gen-9 and a formation temperature of 80 degrees F, gives a salinity of 15,000 ppm NaCl equivalent. · Albian Interval: (Alpine #1 well depth 5150-5204 feet) There is a collection of thin sands in this well and a complete set oflogs is available. Rt is taken from the shallow MWD tool because of minimum exposure time to invasion and superior vertical resolution in three-foot thick beds. Porosity comes from the density log. Rt = 3.2, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The Calculation yields an Rwa equal to 0.293. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100 degrees F, gives a salinity of 15,000 ppm NaCl equivalent. . Sag River Formation: (Nechelik #1 well depth 8432-8480 feet) This is a thick, clean, uniform sand interval with a complete set of logs. Rt = 1.9, Raw density = 2.32, m = 1.7, Porosity = (2.65-2.32) / (2.65-1.0) = 0.20 The calculation yields an Rwa of 0.145 and with a formation temperature of 165 degrees F, produces a salinity value of 18,000 ppm NaCl equivalent. · Ivishak Formation: (Nechelik #1 well depth 9420-9460 feet) This lower sand member has the lowest resistivity and greatest SP excursion. 21 e e Rt = 3.3, Raw density = 2.35, m = 1.8, Porosity = (2.65-2.35) / (2.65-1.0) = 0.18 The calculated Rwa equals 0.15 and with a formation temperature of 185 degrees F, a salinity of 17,000 ppm NaCl equivalent is obtained from the Schlumberger chart. Water Sample Analyses The following water samples were obtained from drill stem and production tests in the general Colville Delta area. · Colville #1 well 7922 feet · 14 miles Northeast · 22,485 mg/l TDS (tested) Shublik Formation · Colville #1 well 9073 feet · 14 miles Northeast · 24,004 mg/l TDS (tested) Lisburne Formation · Kalubik #1 well 5050-5250 feet Albian Interval · 17 miles Northeast · Flowed 151 barrels to surface · 24,300 mg/l TDS (average oftests) · Kalubik Cr. #1 well 9047-9188 Lisburne Formation · 21 miles East · Flowed 325 barrels of water · 21,847 mg/l TDS (tested) · Mukluk well 7490-7520 Ivishak Formation · 23 miles North · Flowed 984 barrels of water · 11,000 ppm chloride tested · 18,150 mg/l TDS (calculated) · Mukluk well 8145-9860 Lisburne Formation · 23 miles North 22 e e · Flowed 1750 barrels of water · 11,000 ppm chloride tested · 18,500 mg/l TDS (calculated) Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Permit Application, Appendix D, previously submitted to the Commission in September 1997. 23 e e Alpine Area Injection Order 20 AAC 25.402 (c)(13) Aquifer Exemption No underground sources of drinking water (USDW) have been identified within the Colville River Unit area. Since there are no USDW's at Alpine, an aquifer exemption per 20 AAC 25.440 is not applicable. The Colville River Unit Area includes; Township 11N Range 4E - (Umiat Meridian) Sections 1-5 all, 7-16 all, 21-27 all. Township IIN Range 5E - (Umiat Meridian) Sections 1-24 all, 29-30 all. Township 12N Range 3E - (Umiat Meridian) Sections 25-27 all, 34-36 all. Township 12N Range 4E - (Umiat Meridian) Sections 20-21 all, 22 excluding portion in Survey USS 9502 (2), 23-27 all, 28-32 excluding portions offshore, 33-36 all. Township 12N Range 5E - (Umiat Meridian) Sections 1-36 all. Township 13N Range 5E - (Umiat Meridian) Sections 9-10 all, 15-22 all, 26-36 all. 24 e . Alpine Area Injection Order 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery Miscible Injectant Criteria The initial reservoir pressure at Alpine is about 3200 psi. Reservoir simulations indicate that the reservoir pressure will decrease about 200 psi during the first several years of production. The Miscible Injectant will be designed to be miscible 100 psi below the projected reservoir pressure. The initial Miscible Injectant composition is therefore designed to be fully miscible with reservoir oil at a reservoir pressure of 2900 psi. The actual miscible injectant may have a lower MMP than this target MMP of2900 psi based on the available enriching components. Fine Grid Compositional Model Results Two different 3-dimensional, fine grid, fully compositional models were developed to estimate the recovery for different development options. The models indicated that miscible WAG could increase individual pattern recoveries by 10-12% OOIP over waterflooding. Full Field Model Results The recovery estimates for both the original waterflood/gas cycling pIan of development and the new enriched miscible gas plan of development come from state-of-the-art reservoir simulations with a compositional simulator. The most current simulations for the full-field Alpine model indicate an ultimate recovery of about 329 MMBO for the original waterflood plan of development and 429 MMBO for the proposed enriched miscible gas plan of development. Thus, the proposed plan of development is expected to increase ultimate recovery by an additional 1 00 MMBO over the original plan of development. This equates to an improvement in recovery of approximately 11 % ofthe OOIP. Surveillance Plans to Evaluate Development Plans and Progress The following surveillance plans will provide routine surveillance data that will be incorporated into various models to determine flood performance and optimize the plan of development: 1. Productivity Measure oil rates with well tests, identify skin damage with production performance and pressure transient analysis. Evaluate the effective producing length with spinner surveys. 2. Water Injectivity 25 e e Identify skin damage with injection performance and pressure transient analysis. Determine effective injection length with spinner surveys. 3. WAG Injection Rates Measure reduction in water and gas rates during alternating water and gas injection cycles. 4. Offtake Management Monitor reservoir pressures to maintain all patterns above the bubble point. Adjust the MME ofthe miscible injectant to keep it miscible below the average reservOlr pressure. 5. Water Injection Slug Size Prior to MW AG Injection Monitor water injection volumes to determine the optimal timing for conversion to miscible WAG. Monitor water production in offset producers to confirm performance predictions. 6. Miscible Injectant Slug Size Monitor gas production in producers and estimate the volumes of returned miscible injectant for each pattern. Monitor miscible injectant volumes on the HCPVi basis. This information will determine when to convert patterns to chase water. 26 · e Alpine Area Injection Order Recommended Conclusions ARCO Alaska, Inc., as CRU Operator, respectfully proposes that the Commission make the following conclusions. 1. The Alpine MW AG project involves the application of a tertiary enhanced oil recovery method in accordance with sound engineering principles. 2. The Alpine Miscible WAG project is reasonably expected to result in a significant increase in the amount of crude oil that ultimately will be recovered. 3. The Alpine Miscible WAG process must be started early in the life of the field to maximize ultimate recovery due to productivity impacts after water breakthrough and a limited MI supply generated from oil production. 27 · e Alpine Area Injection Order Requested Decisions ARCO Alaska, Inc., as CRU Operator, respectfully proposes that the Commission issue an injection order authorizing the underground injection of water and miscible enriched natural gas for enhanced oil recovery in the Alpine Pool. 28 EXHIBIT 1 PROPOSED ALPINE DEVELOPMENT WELLS D1 1A 1 1 - NA~UK 1 D2 . - 1" = October 19, i 999 e e Exhibit 2 Alpine Injection Order Affidavit of R. Scott Redman STATE OF ALASKA THIRD JUDICIAL DISTRICT I, R. Scott Redman, declare and affIrm as follows: 1. I am the Alpine Reservoir Engineer for ARCO Alaska, Inc., the designated operator of the Colville River Unit (which includes the Alpine Pool). 2. On October 18, 1999, I caused copies of the Area Injection Order Application to be provided to the following surface owners and operators of all land within a quarter-mile radius of the proposed injection area: Operator: ARCO Alaska, Inc. Attention: Mr. Mark Ireland P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mr. Mike Kotowski Anchorage, AK 99510 Kuukpik Corporation Attention: Mr. Isaac Nukapigak P.O. Box 187 Nuiqsut, AK 99789-0187 Dated: UC+ /& ,1999. d~ Declared and affIrmed before me this ! gP;ay of (};~ ' 1999. ~~~~ My commission Expires: jl~ /6 ( ;l D() 0 , i. \ l [ Ii { t ( .. .',' . ,\\~ ~ L. Ð.1b' f~, \.'¿.,y~. ~ !) f/ CI ~f"ð:t tf""".,. ~__~V~. ~<riI.!Im 8('~~", <,,; ~-. n.... ~ ~ .'\i':';' ,... ~ -;r. \!J;~'vl ~j(1,~'¿ . ''''rt\''''' ~ 'l:~. ~ œ:t~A ff9"'!t~~~_ :::: . ':Þ,. i "" 0 _ Fò!J~¡¡"~I..' - . 1') ....- _ .t)~........ . -- . . ...,. It -¿ ~·«:OFN ~.. .,¿ ".." 11 ~,. /,,/ *' llllli 29 Exhibit 3 Miscible WAG Substantially Increases Oil Recovery 0.6 0.5 - a.. 8 0.4 c o ''¡:¡ (.) CI:I J: 0.3- ~ CI) :::- o (.) ~ 0.2- Õ 0.1 - - Base WF MF,23%HCPV o o 0.2 0.4 HCPV total Injection 0.6 0.8 Simulation of Stillstand Pattern October 19, 1999 0.14 0.12 - ~ G> 0.1- > o U G> 0.08 - a:: «:S ... 5$ 0.06 - E G> U 0.04 c: 0.02 o o .. VÞ ~ ., ø ø ø 4/? " Klean 0.1 0.2 ., ø lean It MI , , Jif tailgas ., 0.3 Enrichment, fraction C2+ Exhibit 4 e 0.4 Simulations of Transgressive Pattern October 19, 1999 2000 1800 - 1600 - :>. 1400 -.., "' 1200- C ...... 1000- CD ..... 800- ø 600- 400 - 200 - o o Oil production rate Water Injection rate 2000 4000 6000 8000 Time, Days 10000 12000 g 0.7 ~ 0.6- 1! - 0.5- ~ c o 0.4 - ~ ~ 0.3- '- .E 0.2 - > a.. 0.1 - ~ 0 o Wateñlood Breakthrough ~ 1.1 % HCPV /year ~ 4.3 % HCPV/year 2000 4000 6000 8000 Time, Days 10000 Predictions show that water breakthrough significantly reduces injectivity and productivity 12000 Exhibit 5 October 19, 1999 Exhibit 6 0.16 0.06 e: 0.14 - ~-tI! 0 0.05 0 >: g 0.12 10.. 0.04 - II> > +:: . 0 (J (,) m 0.1 II> 0.03 - ... a: - ~ =a. 0.02 - 0- ~ 0.08 - -0 0 .so (J !: !: 0.01 - () II> 0 II: 0.06 E+:: II> (,) Õ ... ell (,) ... Š 0.04 - .5- 0.1 0.2 03 "C !: ___0.3 -wfBT II> ___0.2 - () c E ~ -0.02 - () 0.02 0 ... (,) (J If¡ --e--0.3 .5 i5 -0.03 - 0 -wf controled by prod 0 0.1 0.2 0.3 -0.04 HCPV Water pre injection HCPV Water preinjec1:ion Data show water injection periods greater than 0.1 and less than 0.25 favored Maximum around 19% HCPV for 0.2, 0.25, and 0.3 HCPV MI Slug Sizes Stillstand Model, span=2/3 October 19, 1999 1600 1400 - >- .g 1200- J5 ..... en <If 1000 - 'S a:: c: 800 o ~ () '2' 600- :¡.,. () 'S 3= 400 200 o o J ..' 1000 2000 , .t I 3000 4000 Miscible Flood Waterflood 5000 Time, days 6000 Exhibit 7 1000 9000 10000 8000 October 19, 1999 Exhibit 8 0.16 Q. 8 0.14 - c: .2 0.12 - - U «I .:: 0.1- :>; ... (IJ :> 0.08 - o u (IJ a:: 0.06 16 - ¡ 0.04 E e 0.02 - u c: - o o 0.1 0.2 0.4 0.3 Slugsize, HCPV MI Slugsize Dependence for Stillstand simulations at W AG=O.5 October 19, 1999 Exhibit 9 PIN] Blocked Line . Additions! Modifications Normal Fuel Gas ..........." ^ ~ ";l( , f ~ ') Water MI GULG MI LG/GL >1 ! ) 9, 1999 October "( W' Backup Fuel Gas 'W '1"1' A Recycle ~ [!ill ~ Exhibit 10 :NE October 19, 1999 30 AI pi ne I Supply Forecas 5 10 15 20 25 Time. Years o 90 80 70 60 50 40 20 10 o 1 >- ~ c ii: u en :iE :iE J!i ~ II: c o '.;:I (.) () '2" :iE IN THE ENRICH MISCIBLE WAG N1A TEMPTjnON 1 NECHjUK 1 D1 Core Area Peripheral Area NA~K 1 - PLAN Exhibit 11 2 . - 1" :::: October 19, 1999 Exhibit 12 ALPIN OIL POOL SECTIONS .... /DIXE 6 5 4 3 2 6 5 2 7 8 9 10 11 12 8 9 10 Jf' '0 26 34 35 3N"R5E 6 5 4 R5E F rDR ¡ 1 2 " 12 7 8 9 10 11 17 13 18 17 16 15 14 18 13 17 15 15 19 20 21 22 23 24 24 30 29 28 27 26 25 31 32 33 Tl3N 35 35 5 2 6 7 II 9 10 11 TEM'Tf:!TIa~ if:! rl::Mr TrTJ:~ 1 11 IÞ 1 15 14 21 22 7 18 18 19 30 11 R3: 11"" R3:: 31 6 12 7 13 18 18 24 19 19 25 30 29 25 25 30 EXHIBIT 13 HRUN 1 T ..-ø~INE u (/) (/) ro ..... ;::I ..., ..... CD Q Q ::J t H \-( IBIT 15 l E ^ . T /Ø-INE dark bioturbated ne Siltstone and silt~vf bu rrowed 'I¡,( E EXHIBIT 14 TOP ALPI DEPTH STRUCTURE ,- A !lilt 1 ~ ~ ~ 'U o <-- 8 O(;tabcr 19, 1 oar: Toe +/- 500j above Alpind . Exhibit. Colville River Field Injector Completion Schematic ~~ 4-1/2" Camco "A-1" SSSV (2.125" ID) in DB-6 Lock (3.812" ID) @ 1,000' MD ¡:; ,~: 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2400' TVD cemented to surface 9-5/8" TAM Port Collar @1000' 4-1/2" 12.6 ppf L-80 IBT Mod. tubing (Jet Lube Run'n'Seal) Packer Fluid mix: 9.2 ppg KCI Brine with EC-1124A and 1200' diesel cap 1 - Baker 8-3 Packer (3.875" ID) 2 - 4-1/2" joints (2) blank tubing 3 - HE8 "XN" (3.725" ID) LN 4 - 4-1/2" joint tubing 5 - 4-1/2" WLEG .... -.... ...... ...... ........ ... ......... 6-1/8" Openhole .... ..... ..... ....... ..... ...... ..... .... , . 7" 26 ppf L-80 BTC Mod Production Casing @ 90 deg Updated 5/11/99 Exhibit 17 Alpine Slimtube, Original MI Composition Lean 100 Slimtube 95 - . Gas >f¿ (Mole%) (I 90 - 5= c.. . N2 0.19 C'! 85 - ,.... CO2 0.79 @ ~ 80 - Cl 68.48 () 2000 cell Simulation > 75 - C2 12.68 0 u Core Labs () C3 13.56 a:: 70 - . ARCO C4 0.58 65 C5 0.67 60 C6 0.06 2500 3000 3500 4000 4500 C7 -8+ 0.00 Pressure, psi October 19, 1999 Exhibit 18 Alpine Slimtube, Rich MI Composition Rich Slimtube 105 Gas (Mole%) ';/:!. 100- o~ N2 0.43 :> Q.. CO2 0.68 ~ 95 - ,... @ Cl 61.00 ~ C2 9.96 C1) :> 90 - 2000 cell Simulation 0 C3 12.90 (.) C1) Core labs 7.38 a: C4 85 - C5 4.04 C6 1.64 80 C7 -8+ 1.92 1500 2000 2500 3000 3500 Pressure, psi October 19, 1999 " :; 0.3- ü: Q) c :E (.) 0.25 .¡: c III c .2 0.2 ë cu '- - if 0.15 - () E .s:::. (.) .~ 0.1 III Exhibit 19 0.4 0.35 - N2 C02 Cl C2 C3 C4 C5 C6 C7 -8+ -+- MME - Analytical Method Component Alpine Alpine Lean Enriching Gas Fluid (Mole%) (Mole%) Rich MMP series Lean MMP series Reservoir Pressure 0.53 0.56 70.08 11.17 12.14 4.52 0.86 0.10 0.03 0.06 0.48 25.70 17.49 34.00 16.96 4.26 0.77 0.26 Initial Solvent Composition 0.05 - o 1800 2050 2300 2550 2800 3050 3300 3550 3800 Pressure, psi Slimtube Series Above and Below Reservoir Pressure October 19, 1999 >- g -I o J: I::: -I GAPI Exhibit BERG RUND 1 S$TVD FEE' 150 6400 HRZ 6500 6500 S.HRZ K-1 6700 lCU 6800 6800 -3. ALPINE 7000 7100 7200 7300 . . Exhibit 20 Alpine #1 and Neve #1 Elastic Properties and Strength from Laboratory Tests Ne\€ #1 De pth Plug Rock Conf. Dynamic Dynamic Static Static Unconf. feet Direction Type Press EMOD PR EMOD PR Strength psi Mpsi Mpsi psi 7259.50 H Silt 1500 3.02 0.354 2.42 0.265 5000 2500 3.11 0.360 2.61 0.279 7261.60 V Shale 1500 2.01 0.395 1.72 0.305 4580 2500 2.10 0.399 1.95 0.285 7262.50 V Shale 1500 1.68 0.398 1.55 0.352 fracture 2500 1.72 0.404 1.64 0.364 7263.60 V Shale 1500 1.72 0.415 1.37 0.371 4680 2500 1.74 0.418 1.51 0.385 7265.30 H Shale 1500 2.70 0.390 2.15 0.366 fracture 2500 2.77 0.394 2.35 0.364 A \€rage 2.26 0.39 1.93 0.33 4753 7285.3 V Sand 1500 3.32 0.262 2.35 0.214 7760 2500 3.50 0.274 2.47 0.208 7297.3 V Sand 1500 3.30 0.266 2.41 0.220 8440 2500 3.41 0.276 2.51 0.225 7317.25 V Sand 1500 3.12 0.284 2.25 0.215 7940 2500 3.37 0.294 2.38 0.218 7327.25 V Sand 1500 3.52 0.285 2.44 0.225 8290 2500 3.42 0.312 2.51 0.217 A \€rage 3.37 0.28 2.42 0.220 8108 Alpine #1 7169.8 H Sand 1500 3.69 0.244 2.95 0.195 2500 3.83 0.242 3.05 0.188 7173.5 H Sand 1500 3.98 0.246 3.42 0.212 2500 4.24 0.270 3.55 0.222 7173.8 V Sand 1500 3.95 0.247 3.39 0.208 4410 2500 4.10 0.249 3.47 0.217 7174.8 H Sand 1500 2.56 0.353 2.12 0.235 2500 2.68 0.376 2.31 0.255 7176.3 V Sand 1500 3.00 0.321 2.44 0.258 6540 2500 3.14 0.320 2.47 0.267 A \€rage 3.52 0.29 2.92 0.230 5475 . . Exhibit 22 Stimplan Fracture Growth Model - 5 BPM Stress (psi) · .. , · .. . ... ..................~........ I ARCO Exploration and Production Technology Max Width 0.09 in At Closure iii . . 6700 ................ ..:..... ... ..........:...................:............. .......... ........ ······i·····~·····r· · . · . · . · . · . · . i i · . · . · .. . i l.___..j : .- . ......p.............. · . · . · . · . · . i ~ · : ~ · . · . II ·t············ ¡'····..t·····r· I II" · ;O.. · I.. · II" · ... · ... · :f., · ~.. ¡ i ¡ ¡ · I.. .~...... ...... I.....t.....t I 6800 ..................¡ .... ............-... ...... ....... T..···....··· ..... · . · . · . · . · . i i · . · . .................. ~ ... .... ..........................:f..... .........., I · · · ! ............ II........ I' ........ ................ ........ .......... T ....... ..... ..... · : · · · · · ! ..... ......... .....¡...... ....... ......................... .o............. .......... · . . c--=:> ~ 6900 7000 7100 3500 4000 4500 5000 5500 0.0 500 1000 1500 Fracture Penetration (ft) Alpine WD-02 Water Iniectlon 5000 2000 1000 500 ~ .¡¡¡ ~ 2: ~ 200 ::; c; tJ> tJ> Q) 100 ð:: 1ií z 50 20 10 5.0 2~0 5.0 1'0 20 50 100 200 500 1000 2000 Time (min) 5000 1000020000 50ÓOO 200000 50döoo #4 tI - .~ . '"' " TONY KNOWLES, GOVERNOR AI,ASKA OIL A5D GAS CONSERVATION COHMISSION 3001 PORCUPINE DRIVE ANCHORAGE. ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 October 5, 1999 Mark Ireland Alpine Development Manager ARCO Alaska, Inc. PO Box 100360 Anchorage,AJ< 99510-0360 Re: Alpine Area Injection Order Request Dear Mr. Ireland: After completing an initial review of the Alpine Area Injection Order application, the Commission has a few additional questions about the project, which we would like you to address during the scheduled public hearing. Detailed information should also be submitted with the "final" Area Injection Order application. Miscible Injectant Supply What is the optimal MI composition? What are the recovery impacts of the chosen MI composition? What were the tradeoffs and parameters selected? What are the facility constraints? Were sensitivity analyses run? What were the results? Proper Stag;ing of the EOR Project How did you arrive at the conclusions detailed in the staging section of the application? What are the permeability affects and what causes them? How will you verify your ) analysis? What is the proposed surveillance program? Please provide a detailed discussion of ARCO's planned surveillance program. lnjectivity Issues What are the optimal water and gas slug sizes and what is the basis for that determination? Solvent Supply Please describe the process equipment and how it will affect the solvent supply. What is the startup schedule at this time (#Wells/yr) and how do you plan to stage it? Mr. Mark Ireland Alpine Area Injection Order Request Page 2 . . October 5, 1999 ¡J " .. Fracture Information Please provide dipole sonic or other data to support your rracturing analysis. Explain the basis for the rracture growth estimates within the shale intervals. Please.provide lab data or other reports that support these determinations. Miscible Injectant Criteria Please provide a more detailed discussion of the pressure regime and fluid miscibility. How did you arrive at these determinations? What is the target reservoir pressure with respect to minimum miscibility pressure (MMP)? Full Field Model Results Please describe your surveillance plans that will be necessary to evaluate development plans and progress. The Commission has scheduled a public hearing for October 19, 1999. Please notify us as soon as possible if you need additional time to prepare for the public hearing. We will need to publish a second public hearing notice if we delay the hearing. Robert N. Christenson, P.E. Chairman #3 . . Notice of Public Hearing ORIGINAL STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Colville River Unit Area Injection Order ARCO Alaska, Inc. by letter dated September 3, 1999, has requested an order allowing the injection of enhanced recovery fluids in the Colville River Unit on the North Slope. The requested order would authorize a miscible water-alternating-gas project in the Alpine Oil Pool. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM, October 1, 1999 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on this matter. If the protest is timely filed a hearing on the matter will be held at the above address at 9:00 AM on October 19, 1999, in conformance with 20 AAC 25.540. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 before October 13, 1999. Robert N. Christenson, P.E. Chairman Published September 16,1999 ADN AO# 02014011 .fidavit of Publication . Ad # Run Dates ED Po # Price per Account day 168674 09/16/99 ON 02014011 $68.75 STOF0330 STOF0330 $68.75 STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva A!exie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Legal Clerk:2~¿Ç~J:;;~~._~~ Notice Of PUblic Heoring STATE OF ALASKA Alaska Of/and Gas Conservotiøn Commission Re:Colv¡IIe River.· Unit Area Injection Order ARCO Alaska, Inc. by let" ter . dated. " September .3 1999, has reqUested ah order <¡II owing the injection ~f enhanced recovery fluids In the. COlville River Unit on.. the North Slope. The ;;reque~."q, order wOUld "authorlZe a miséiblewater. ,..ql.t!¡I't)j)ting·qas . proíec.t In "~ ~h'lne Oil Pool. A person Who .maYbe harmed if the requested Qrder Is issued may fife a written protest priQr to 4'00 PM!' October 1;1999 with . tl1e'Alas~a Oil and Gas ConservahPO ·.CammisSiQn 3001 POr"cupineDrive' Anchqrage, AlaskQ 99501: and re<luest Q hearing 00' Subscribed and sworn to me before this date: ______~~J~ý_q________ Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: 1c:2~/o / __-9IJÉiJlb~m___- \\l ((( {{ {ftll \\ "A Q 1'1'. ,\\:~~\.. ,', '~O""'r '"' ..s..'.. .__ .. ~';- ~ .)..~, ......... ...A b '--;:.. ~ (I. ,~~O' ... ".. r ,.,.. -::::. \"",; /. ~ ...~, ..-- :::r ".. .... \c, . ~ :::, : !..;~"'B\..', . ~~ -J£........ ~~~;;i~it........i . '"' ~ .~~ .--" . " ~~\ ··.~.........œé ..~., ~ ~ . ·z ~_"þß-;' , . to :\~ /,/,/ &øire&' ),\ :/j))J)JJi))\ I :r~e~a~~ I~th~i~}~ the motler. wi II be'. held a.t J .the abave Od(/te$$at9'00 AM on OctQ~r )9, 1999 . in conformancellVith 20 ÁAC 25.540. if OQ prote..' is filèd t~e CQmml$slonlolW CÖI1: sIder the,' issuance. Of the Qrder without 0 heorjns. If YQU ore. a Person w'ithe disab!lity who maY need~ spedal . modification in order . tQ comment or to atfend tlU! PUblic h~ring pleose cQntact DIona Fleck ft f~~221 befQreQctober Is/RQbért N. ¢hristenSOl1 P£., Chairman Pub.: Sept. 16, 1999 . -----------.:...---'........:...-~-~~ < ' 9~ DRI / MCGRAW HILL RANDALL NOTTINGHAM 24 HARTWELL LEXINGTON MA 02173 OVERSEAS SHIPHOLDING GRP ECON DEPT 1114 AV OF THE AMERICAS NEW YORK NY 10036 ALASKA OFC OF THE GOVERNOR JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON DC 20001 ARENT FOX KINTNER PLOTKIN KAHN LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON DC 20036-5339 LIBRARY OF CONGRESS STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON DC 20540 e ( I \)V\~ .' PlRA ENERGY GROUP LIBRARY 3 PARK AVENUE (34TH & PARK) NEW YORK NY 10016 NY PUBLIC LIBRARY DIV E GRAND CENTRAL STATION POBOX 2221 NEW YORK NY 10163-2221 OIL DAILY CAMP WALSH 1401 NEW YORK AV NW STE 500 WASHINGTON DC 20005 US MIN MGMT SERV CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON VA 20170-4817 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON DC 20585 ) , I · 1 e TECHSYS CORP BRANDY KERNS PO BOX 8485 GATHERS BURG MD 20898 DPC DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH FL 32118 AMOCO CORP 2002A LIBRARY/INFO CTR POBOX 87703 CHICAGO IL 60680-0703 LINDA HALL LIBRARY SERIALS DEPT 5109 CHERRY ST KANSAS CITY MO 64110-2498 MURPHY E&P CO ROBERT F SAWYER POBOX 61780 NEW ORLEANS LA 70161 e US GEOL SURV LIBRARY NATIONAL CTR MS 950 RESTON VA 22092 SD DEPT OF ENV & NATRL RESOURCES OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY SD 57702 ILLINOIS STATE GEOL SURV LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN IL 61820 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA KS 67202-1811 UNIV OF ARKANSAS SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE AR 72701 \ , e CROSS TIMBERS SUSAN LILLY 210 PARK AVE OKLAHOMA CITY OPERATIONS STE 2350 OK 73102-5605 IOGCC POBOX 53127 OKLAHOMA CITY OK 73152-3127 OIL & GAS JOURNAL LAURA BELL POBOX 1260 TULSA OK 74101 BAPI RAJU 335 PINYON LN COPPELL TX 75019 US DEPT OF ENERGY ENERGY INFORMATION ADMINISTRATION MIR YOUSUFUDDIN 1999 BRYAN STREET STE 1110 DALLAS TX 75201-6801 e DWIGHTS ENERGYDATA INC JERLENE A BRIGHT DIRECTOR PO BOX 26304 OKLAHOMA CITY OK 73126 R E MCMILLEN CONSULT GEOL 202 E 16TH ST OWASSO OK 74055-4905 CH2M HILL J DANIEL ARTHUR PE PROJ MGR 502 S MAIN 4TH FLR TULSA OK 74103-4425 MARK S MALINOWSKY 15973 VALLEY VW FORNEY TX 75126-5852 DEGOLYER & MACNAUGHTON MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS TX 75206-4083 MOBIL OIL CORP MORRIS CRIM POBOX 290 DALLAS TX 75221 GCA ENERGY ADV RICHARD N FLETCHER 16775 ADDISON RD STE 400 DALLAS TX 75248 JERRY SCHMIDT 4010 SILVERWOOD DR TYLER TX 75701-9339 CROSS TIMBERS OIL COMPANY MARY JONES 810 HOUSTON ST STE 2000 FORT WORTH TX 76102-6298 SHELL WESTERN E&P INC K M ETZEL POBOX 576 HOUSTON TX 77001-0574 e . GAFFNEY, CLINE & ASSOC., INC. ENERGY ADVISORS MARGARET ALLEN 16775 ADDISON RD, STE 400 DALLAS TX 75248 MOBIL OIL JAMES YOREK POBOX 650232 DALLAS TX 75265-0232 STANDARD AMERICAN OIL CO AL GRIFFITH POBOX 370 GRANBURY TX 76048 PRITCHARD & ABBOTT BOYCE B BOLTON PE RPA 4521 S. HULEN STE 100 FT WORTH TX 76109-4948 ENERGY GRAPHICS MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON TX 77002 H J GRUY ATTN: ROBERT RASOR 1200 SMITH STREET STE 3040 HOUSTON TX 77002 RAY TYSON 1617 FANNIN ST APT 2015 HOUSTON TX 77002-7639 BONNER & MOORE LIBRARY H20 2727 ALLEN PKWY STE 1200 HOUSTON TX 77019 PETRAL CONSULTING CO DANIEL L LIPPE 9800 RICHMOND STE 505 HOUSTON TX 77042 MARK ALEXANDER 7502 ALCOMITA HOUSTON TX 77083 . . PURVIN & GERTZ INC LIBRARY 2150 TEXAS 600 TRAVIS HOUSTON TX COMMERCE TWR ST 77002-2979 CHEVRON PAUL WALKER 1301 MCKINNEY RM 1750 HOUSTON TX 77010 OIL & GAS JOURNAL BOB WILLIAMS 1700 W LOOP SOUTH STE 1000 HOUSTON TX 77027 MOBIL OIL N H SMITH 12450 GREENS POINT DR HOUSTON TX 77060-1991 MARATHON OIL CO GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON TX 77210 UNOCAL REVENUE ACCOUNTING POBOX 4531 HOUSTON TX 77210-4531 EXXON EXPLORATION CO. T E ALFORD POBOX 4778 HOUSTON TX 77210-4778 PETR INFO DAVID PHILLIPS POBOX 1702 HOUSTON TX 77251-1702 PHILLIPS PETROLEUM COMPANY W ALLEN HUCKABAY PO BOX 1967 HOUSTON TX 77251-1967 EXXON CO USA RESERVES COORD RM 1967 POBOX 2180 HOUSTON TX 77252-2180 . - EXXON EXPLOR CO LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON TX 77210-4778 CHEVRON USA INC. ALASKA DIVISION ATTN: CORRY WOOLINGTON POBOX 1635 HOUSTON TX 77251 PHILLIPS PETR CO ALASKA LAND MGR POBOX 1967 HOUSTON TX 77251-1967 WORLD OIL MARK TEEL ENGR ED POBOX 2608 HOUSTON TX 77252 EXXON CO USA J W KIKER ROOM 2086 POBOX 2180 HOUSTON TX 77252-2180 EXXON CO USA GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON TX 77252-2180 PENNZOIL E&P WILL D MCCROCKLIN POBOX 2967 HOUSTON TX 77252-2967 MARATHON MS. NORMA L. CALVERT POBOX 3128, STE 3915 HOUSTON TX 77253-3128 PHILLIPS PETR CO ERICH R. RAMP 6330 W LOOP SOUTH BELLAIRE TX 77401 PHILLIPS PETR CO PARTNERSHIP OPRNS JERRY MERONEK 6330 W LOOP S RM 1132 BELLAIRE TX 77401 e e EXXON CO USA M W ALBERS RM 1943 POBOX 2180 HOUSTON TX 77252-2180 CHEVRON CHEM CO LIBRARY & INFO CTR POBOX 2100 HOUSTON TX 77252-9987 ACE PETROLEUM COMPANY ANDREW C CLIFFORD PO BOX 79593 HOUSTON TX 77279-9593 PHILLIPS PETR CO JOE VOELKER 6330 W LP S RM 492 BELLAIRE TX 77401 TEXACO INC R EWING CLEMONS POBOX 430 BELLAIRE TX 77402-0430 e WATTY STRICKLAND 2803 SANCTUARY CV KATY TX 77450-8510 INTL OIL SCOUTS MASON MAP SERV INC POBOX 338 AUSTIN TX 78767 DIANE SUCHOMEL 10507D W MAPLE WOOD DR LITTLETON CO 80127 AMOCO PROD CO LIBRARY RM 1770 JILL MALLY 1670 BROADWAY DENVER CO 80202 JERRY HODGDEN GEOL 408 18TH ST GOLDEN CO 80401 e TESORO PETR CORP LOIS DOWNS 8700 TESORO DR SAN ANTONIO TX 78217 ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON CO 80122 GEORGE G VAUGHT JR POBOX 13557 DENVER CO 80201 C & R INDUSTRIES, INC. KURT SALTSGAVER 1801 BROADWAY STE 1205 DENVER CO 80202 NRG ASSOC RICHARD NEHRING POBOX 1655 COLORADO SPRINGS CO 80901-1655 RUBICON PETROLEUM, LLC BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS CO 80906 RUI ANALYTICAL JERRY BERGOSH POBOX 58861 SALT LAKE CITY UT 84158-0861 MUNGER OIL INFOR SERV INC POBOX 45738 LOS ANGELES CA 90045-0738 US OIL & REFINERY CO TOM TREICHEL 2121 ROSECRANS AVE #2360 ES SEGUNCO CA 90245-4709 ANTONIO MADRID POBOX 94625 PASADENA CA 91109 e e JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE ID 83702 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 BABSON & SHEPPARD JOHN F BERGQUIST POBOX 8279 VIKING STN LONG BEACH CA 90808-0279 ORO NEGRO, INC. 9321 MELVIN AVE NORTHRIDGE CA 91324-2410 PACIFIC WEST OIL DATA ROBERT E COLEBERD 15314 DEVONSHIRE ST STE D MISSION HILLS CA 91345-2746 SANTA FE ENERGY RESOURCES INC EXPLOR DEPT 5201 TRUXTUN AV STE 100 BAKERSFIELD CA 93309 US GEOL SURV KEN BIRD 345 MIDDLEFIELD RD MS 999 MENLO PARK CA 94025 H L WANGENHEIM 5430 SAWMILL RD SP 11 PARADISE CA 95969-5969 US EPA REGION 10 LAURIE MANN OW-130 1200 SIXTH AVE SEATTLE WA 98101 - e 76 PRODUCTS COMPANY CHARLES BURRUSS RM 11-767 555 ANTON COSTA MESA CA 92626 TEXACO INC PORTFOLIO TEAM MANAGER R W HILL POBOX 5197X BAKERSFIELD CA 93388 SHIELDS LIBRARY GOVT DOCS DEPT UNIV OF CALIF DAVIS CA 95616 ECONOMIC INSIGHT INC SAM VAN VACTOR POBOX 683 PORTLAND OR 97207 MARPLES BUSINESS NEWSLETTER MICHAEL J PARKS 117 W MERCER ST STE 200 SEATTLE WA 98119-3960 PATTI SAUNDERS 1233 W 11TH AV ANCHORAGE AK 99501 DEPT OF REVENUE BEVERLY MARQUART 550 W 7TH AV STE 570 ANCHORAGE AK 99501 FAIRWEATHER E&P SERV INC JESSE MOHRBACHER 715 L ST #4 ANCHORAGE AK 99501 STATE PIPELINE OFFICE LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE AK 99501 FORCENERGY INC. JIM ARLINGTON 310 K STREET STE 700 ANCHORAGE AK 99501 e e DUSTY RHODES 229 WHITNEY RD ANCHORAGE AK 99501 DEPT OF REVENUE OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE AK 99501 GUESS & RUDD GEORGE LYLE 510 L ST, STE 700 ANCHORAGE AK 99501 TRUSTEES FOR ALASKA 725 CHRISTENSEN DR STE 4 ANCHORAGE AX 99501 YUKON PACIFIC CORP JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE AX 99501-1930 PRESTON GATES ELLIS LLP LIBRARY 420 L ST STE 400 ANCHORAGE AK 99501-1937 GAFO GREENPEACE PAMELA MILLER 125 CHRISTENSEN DR. #2 ANCHORAGE AK 99501-2101 DEPT OF REVENUE OIL & GAS AUDIT FRANK PARR 550 W 7TH AVE STE 570 ANCHORAGE AK 99501-3540 HDR ALASKA INC MARK DALTON 2525 C ST STE 305 ANCHORAGE AK 99503 N-I TUBULARS INC 3301 C STREET STE 209 ANCHORAGE AK 99503 e e ALASKA DEPT OF LAW ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE AK 99501-1994 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS TIM RYHERD 550 W 7TH AVE STE 800 ANCHORAGE AK 99501-3510 BAKER OIL TOOLS ALASKA AREA MGR 4710 BUS PK BLVD STE 36 ANCHORAGE AK 99503 KOREAN CONSULATE OCK JOO KIM CONSUL 101 BENSON STE 304 ANCHORAGE AK 99503 ANADARKO MARK HANLEY 3201 C STREET STE 603 ANCHORAGE AK 99503 e ALASKA OIL & GAS ASSOC JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE AK 99503-2035 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS BRUCE WEBB 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JUL I E HOULE 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES PUBLIC INFORMATION CTR 3601 C STREET STE 200 ANCHORAGE AK 99503-5948 FINK ENVIRONMENTAL CONSULTING, INC. THOMAS FINK, PHD 6359 COLGATE DR. ANCHORAGE AK 99504-3305 AK JOURNAL OF COMMERCE OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B STREET STE #210 ANCHORAGE AK 99503-5911 DEPT OF NATURAL RESOURCES DIV OIL & GAS WILLIAM VAN DYKE 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 e DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JIM STOUFFER 3601 C STREET STE 1380 ANCHORAGE AK 99503-5948 ARLEN EHM GEOL CONSLTNT 2420 FOXHALL DR ANCHORAGE AK 99504-3342 JAMES E EASON 8611 LEEPER CIRCLE ANCHORAGE AK 99504-4209 STU HIRSH 9630 BASHER DR. ANCHORAGE AX 99507 US BLM AK DIST OFC RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE AX 99507-2899 CASS ARlEY 3108 WENTWORTH ST ANCHORAGE AX 99508 TRADING BAY ENERGY CORP PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE AK 99508 e e RUSSELL DOUGLASS 6750 TESHLAR DR ANCHORAGE AK 99507 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE AX 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE AX 99508 UNIVERSITY OF ALASKA ANCHORAGE INST OF SOCIAL & ECON RESEARCH TERESA HULL 3211 PROVIDENCE DR ANCHORAGE AK 99508 US MIN MGMT SERV RICHARD PRENTKI 949 E 36TH AV ANCHORAGE AX 99508-4302 . US MIN MGMT SERV AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE AK 99508-4302 REGIONAL SUPRVISOR, FIELD OPERATNS MINERALS MANAGEMENT SERVICE ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE AK 99508-4363 US MIN MGMT SERV RESOURCE EVAL JIM SCHERR 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4363 JOHN MILLER 3445 FORDHAM DR ANCHORAGE AK 99508-4555 CIRI LAND DEPT POBOX 93330 ANCHORAGE AK 99509-3330 . US MIN MGMT SERV RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4302 US MIN MGMT SERV LIBRARY 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4363 US MIN MGMT SERV FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE AK 99508-4363 USGS - ALASKA SECTION LIBRARY 4200 UNIVERSITY DR ANCHORAGE AK 99508-4667 ANCHORAGE TIMES BERT TARRANT POBOX 100040 ANCHORAGE AK 99510-0040 BRISTOL ENVIR SERVICES JIM MUNTER POBOX 100320 ANCHORAGE AK 99510-0320 ARCO ALASKA INC LEGAL DEPT MARK P WORCESTER POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC LIBRARY POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC LAND DEPT JAMES WINEGARNER POBOX 10036 ANCHORAGE AK 99510-0360 ARCO ALASKA INC SHELIA ANDREWS ATO 1130 PO BOX 100360 ANCHORAGE AK 99510-0360 e e ARCO ALASKA INC JOANN GRUBER ATO 712 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC STEVE BENZLER ATO 1404 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC MARK MAJOR ATO 1968 POBOX 100360 ANCHORAGE AK 99510-0360 ARCO ALASKA INC SAM DENNIS ATO 1388 POBOX 100360 ANCHORAGE AK 99510-0360 PETROLEUM INFO CORP KRISTEN NELSON POBOX 102278 ANCHORAGE AK 99510-2278 ARCO ALASKA INC KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE AX 99510-6105 ALYESKA PIPELINE SERV CO CHUCK O'DONNELL 1835 S BRAGAW - MS 530B ANCHORAGE AX 99512 US BUREAU OF LAND MGMT OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE AX 99513-7599 JWL ENGINEERING JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE AX 99516-6510 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE AX 99517-1303 e tit ALYESKA PIPELINE SERV CO PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE AX 99512 ALYESKA PIPELINE SERV CO LEGAL DEPT 1835 S BRAGAW ANCHORAGE AX 99512-0099 ANCHORAGE DAILY NEWS EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE AK 99514 NORTHERN CONSULTING GROUP ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE AX 99517 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE AX 99518 ASRC CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE AK 99518 OPSTAD & ASSOC ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE AK 99519 ENSTAR NATURAL GAS CO RICHARD F BARNES PRES POBOX 190288 ANCHORAGE AK 99519-0288 MARATHON OIL CO BRAD PENN POBOX 196168 ANCHORAGE AK 99519-6168 e tit SCHLUMBERGER DARREN AKLESTAD 1111 E 80TH AV ANCHORAGE AK 99518 HALLIBURTON ENERGY SERV MARK WEDMAN 6900 ARCTIC BLVD ANCHORAGE AK 99518-2146 JACK 0 HAKKILA POBOX 190083 ANCHORAGE AK 99519-0083 MARATHON OIL CO OPERATIONS SUPT POBOX 196168 ANCHORAGE AK 99519-6168 UNOCAL POBOX 196247 ANCHORAGE AK 99519-6247 UNOCAL KEVIN TABLER POBOX 196247 ANCHORAGE AK 99519-6247 BP EXPLORATION (ALASKA) INC MR. DAVIS, ESQ POBOX 196612 MB 13-5 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA) INC INFO RESOURCE CTR MB 3-2 POBOX 196612 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA) INC SUE MILLER POBOX 196612 M/S LR2-3 ANCHORAGE AK 99519-6612 AMERICA/CANADIAN STRATIGRPH CO RON BROCKWAY POBOX 242781 ANCHORAGE AK 99524-2781 e e EXXON COMPANY USA MARK P EVANS PO BOX 196601 ANCHORAGE AK 99519-6601 BP EXPLORATION (ALASKA) INC BOB WILKS MB 5-3 POBOX 196612 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA) INC PETE ZSELECZKY LAND MGR POBOX 196612 ANCHORAGE AK 99519-6612 BP EXPLORATION (ALASKA), INC. MARK BERLINGER MB 8-1 PO BOX 196612 ANCHORAGE AK 99519-6612 AMSI/VALLEE 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 DEPT OF NATURAL RESOURCES DGGS JOHN REEDER POBOX 772805 EAGLE RIVER AK 99577-2805 COOK INLET KEEPER BOB SHAVELSON PO BOX 3269 HOMER AK 99603 DOCUMENT SERVICE CO JOHN PARKER POBOX 1137 KENAI AK 99611 e e DIANA FLECK 18112 MEADOW CRK DR EAGLE RIVER AK 99577 PINNACLE STEVE TYLER 20231 REVERE CIRCLE EAGLE RIVER AK 99577 COOK INLET VIGIL JAMES RODERICK POBOX 916 HOMER AK 99603 RON DOLCHOK POBOX 83 KENAI AK 99611 PHILLIPS PETR ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI AK 99611 KENAI PENINSULA BOROUGH ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI AX 99611-3029 BELOWICH COAL CONSULTING MICHAEL A BELOWICH HC31 BOX 5157 WASILLA AX 99654 PACE SHEILA DICKSON POBOX 2018 SOLDOTNA AX 99669 ALYESKA PIPELINE SERVICE CO VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ AK 99686 VALDEZ VANGUARD EDITOR POBOX 98 VALDEZ AX 99686-0098 e e PENNY VADLA POBOX 467 NINILCHIK AX 99639 JAMES GIBBS POBOX 1597 SOLDOTNA AX 99669 KENAI NATL WILDLIFE REFUGE REFUGE MGR POBOX 2139 SOLDOTNA AX 99669-2139 VALDEZ PIONEER POBOX 367 VALDEZ AX 99686 UNIV OF ALASKA FAIRBANKS PETR DEVEL LAB DR V A KAMATH 427 DUCKERING FAIRBANKS AK 99701 NICK STEPOVICH 543 2ND AVE FAIRBANKS AK 99701 JACK HAKKlLA POBOX 61604 FAIRBANKS AX 99706-1604 FAIRBANKS DAILY NEWS-MINER KATE RIPLEY POBOX 70710 FAIRBANKS AX 99707 DEPT OF NATURAL RESOURCES DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS AK 99709-4699 ASRC BILL THOMAS POBOX 129 BARROW AX 99723 e e RICK WAGNER POBOX 60868 FAIRBANKS AX 99706 C BURGLIN POBOX 131 FAIRBANKS AX 99707 FRED PRATT POBOX 72981 FAIRBANKS AX 99707-2981 K&K RECYCL INC POBOX 58055 FAIRBANKS AX 99711 RICHARD FINEBERG POBOX 416 ESTER AX 99725 e UNIV OF ALASKA FBX PETR DEVEL LAB SHIRISH PATIL 437 DICKERING FAIRBANKS AK 99775 SENATOR LOREN LEMAN STATE CAPITOL RM 113 JUNEAU AK 99801-1182 SNEA(P) DISTR FRANCE/EUROPE DU SUD/AMERIQUE TOUR ELF CEDEX 45 992078 PARIS LA DE FE FRANCE . UNIVERSITY OF ALASKA FBKS PETR DEVEL LAB DR AKANNI LAWAL POBOX 755880 FAIRBANKS AK 99775-5880 DEPT OF ENVIRON CONSERV SPAR CHRIS PACE 410 WILLOUGHBY AV STE 105 JUNEAU AK 99801-1795 #2 .. . e .. _!"!'t~, ~.' .~:.~ ~INEI FACSIMILE TRANSMITTAL SJlIt:~;T DATE: TO: FAX#: FROM: Of I. I 5 /91 Ú ) (1 <A..J) Mó-. ht{ V' ),10-.7?42.- 12-.. <) t'.?1I!. ~clf\'Vt ~ COMMENTS: IV(2vv;J~ f I-kr€_ ··I~ ~ a. f-J:¡Cbv¡+ . (~j~vJt~J. f\6 h<-e _ f-r")<Ç'.(ll RtL~ Ùu..lI\I2V'S, k'-'" ~ A-tp¡ v\fL /+re.L,^- tIAJ~~~'V'. Ófdc>v:. ,5 C Ô.¡.;- J2rµ~l'" ( . NO. OF PAGES FOLLOWING COVER: - FAX NUMBER (907) 265-1515 VERIFY NUMBER (907) 263-4414 7-Ç. I WI U ~&Dse{/tC'~ J 011'- ð-- ctf( r (/\.. .-f1,"L- fW\~ I. r-rJ:¡'\Jr.:D b \.... '- , v 1...' SEP 13 1999 . . Alpine Area Injection Order 20 AAC 25.402 (c)(3) Affidavit of R. Scott Redmao..~evardimJ Notice to Surface Owne~ R. Scott Redman, on oath, deposes and says: I. I am the Alpine Reservoir Engineer at ARCO A1aska, Inc., the designated operator of the Colville River Unit (which inetudes the Alpine Pool). 2. On September 8, 1999, I caused copies of the Area Injection Order Applìcation to be provided to the surface owner and operators of aU land withìn a quarter mile of the unit as listed below: Operator: ARCO Alaska, Inc. Attention: Mark Ireland P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporatìon Mr. Joe Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 ¿¿ I)~ r..q:~"'- C I" , r...· / .:...- - r:7...re-r- _ ~ 1,\ (' \ ¡" i \f ¡- ~ ) "". . ..:7. ~ __ .-. ,- ,-" Ì' L~~, R. Scott Redman SED 1'7l 1""" \}! 'J''1 9 STATE OF ALASKA ) ) ss. ) ,< ;"·'r>,;"··,,,"1' ; ~ ....' ì\ ,; '-'·....üiLd¡$SlDfJ h,¡~8t:Qr2.Ga TIlIRD JUDICIAL DISTRICT SUBSCRIBED AND SWORN to before me this 13th day of September, 1999. P~tA-:¡ /l1 ~~ NOTARY PUBLIC IN AND FOR ALASKA ~~\\\\\t""""11 ~ ·f. A4""'''~ ~ ........<::1.... ~.... ,.. ...../~ ~. ... ...~~'~ .' .,-p~ t ...'tnT" D'1,.', ~ ~ . .L~J 1.~f\,! ': ~ - . . :::s: ...~. P"i'm, "(' :....:::: ~Ir. tJÁ~t.l-_f /~.§È , ." ~ ."-. ... .. "" .'S:' ~/: ...... .. "'t...... ~ .'/,'.:........, ~~:: .-:\.~ 'íí'M' t. (¡ ¡:. ~\.. \\\~:' l;'¡iiHiIlW\\\'\" . My Commission Expires: ) 0 ~ / Lf - ? 7 7 #1 « ARCO Alaska, Inc. . Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . ..4Ø~ ~~ September 3, 1999 Mr. Bob Christensen, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Area Injection Order Alpine Oil Pool Colville River Unit Dear Chairman Christensen: ARCO Alaska, Inc. (ARCO), as an owner and the operator ofthe Colville River Unit seeks Alaska Oil and Gas Commission (Commission) endorsement and authorization to conduct a Miscible Water-Alternating-Gas Project in the Alpine Oil Pool. Enclosed is the application for this project prepared in accordance with 20 ACC 25.402 (Enhanced Recovery Operations). Pursuant to this objective, ARCO requests the Commission hold a hearing in accordance with 20 AAC 25.540, and that the hearing be scheduled on or after October 12, 1998. Attached are six copies of the application package, which includes the proposed rules, supporting pre-filed testimony,. and exhibits. For additional information supporting either application, please contact R. Scott Redman at 263-4514. Sincerely, 4/VLæL~ Mark M. Ireland Alpine Development Manager R\: ç \ \I to .' ~.. ~. ,,., ~;£P (; -{ 1<3SS «.. 13;),'-.) C,:)';\s. Goro'(f{~\on \';""",,', ").·,·,-.·,,o;..::.ge p.fl\;{\\;J-·· ARGO Alaska, Inc. is a Subsidiary of AtianlicRichfieldCompany · cc: Mr. Kenneth A. Boyd, Director Alaska Department of Natura 1 Resources Division ofOil & Gas 3601 C Street, Suite 1380 Anchorage, Alaska 99503-5948 Ms. Teresa Imm, Resource Development Manager Arctic Slope Regional Corporation 301 Arctic Slope Avenue, Suite 300 Anchorage, Alaska 99518-3035 Mr. Joe Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 Mr. Jerry Windlinger Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Todd Liebel Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 e ('\\lED Rt \,~ ~fl S £.? (;-l '\999 . ^'Jì;,<''''\}'(\' Cctn\lI;O)'" ¡¡.. '" bcc: Mike Erwin Scott Redman Doug Chester Mark Ireland Jim Winegarner Dan Rodgers Antoinette Tadolini Peter Turner Alpine Pile . e ANO 384 ANO 386 ANO 382 ANO 392 ATO 1496 ATO 2002 ATO 926 ATO 2068 e e Alpine Area Injection Order ARCO Alaska, Ine Anadarko Petroleum Corporation Union Texas Petroleum, LLC September 3, 1999 e e Table of Contents Reference Subject Page Introduction 4 20 ACC.25.402(c)(1) Plat of Wells Penetrating Injection Zone 5 20 ACC.25.402(c)(2) Operators and Surface Owners 6 20 ACC.25.402(c)(3) Affidavit of Notice to Surface Owners 7 20 ACC.25.402(c)(4) Description ofthe Proposed Operation 8 20 ACC.25.402(c)(5) Description and Depth of Pool to be Affected 11 20 ACC.25.402(c)(6) Description ofthe Formation 13 20 ACC.25.402(c)(8) Casing Description 14 20 ACC.25.402(c)(9) Injected Fluid Analysis 16 20 ACC.25.402(c)(10) Estimated Pressures 17 20 ACC.25.402(c)(11) Fracture Information 18 20 ACC.25.402(c)(12) Formation Fluid 20 20 ACC.25.402(c)(13) Aquifer Exemption 24 20 ACC.25.402(c)(14) lncremental Hydrocarbon Recovery 25 Recommended Conclusions 26 Requested Decisions 27 2 Exhibit 1 Exhibit 2 Exhibit 3 Exhibit 4 Exhibit 5 Exhibit 6 Exhibit 7 e e List of Exhibits Proposed Alpine Development Wells Alpine Oil Pool Section Boundaries Bergschrund 1 Type Log Alpine Oil Pool Type Log Top Alpine Depth Structure Map Injector Completion Schematic StimPlan Fracture Height Growth Model 3 e e Alpine Area Injection Order Introduction This application seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed Alpine Miscible Water Alternating Gas Project. This application has been prepared in accordance with 20 ACC 25.402 (Enhanced Recovery Operations). On December 3, 1998, the Commission held an Alpine Pool Rules Hearing. This hearing reviewed pool rules and injection disposal but not enhanced recovery operations. On March 15, 1999, the Commission issued Conservation Order #443 establishing Alpine Oil Pool Rules for development. In the Alpine Pool Rules Hearing, ARCO presented the original plan of development as well as a potential new plan of development. Since the Pool Rules hearing, the Alpine Working Interest Owners have been working on obtaining funding approval for the new pIan of development. A description of the original and new plans of development are provided below: Original Plan of Development The scope of the original development included horizontal wells in the center of the field and vertical wells around the periphery. The horizontal wells were on 275-acre spacing and the vertical wells were on 160-acre spacing. The original recovery process was waterflood in the center of the field with gas re-injection around the periphery. The original development was estimated to recover 38% OOIP. New Plan of Development The new development includes only horizontal wells on 135-acre spacing (see Exhibit 1). A Miscible Water-Alternating-Gas (MWAG) process is implemented at startup. The miscible injectant is made from solution gas enriched with C2+ components recovered from the fuel gas. The proposed development is estimated to recover 45% OOIP. 4 e e Alpine Area Injection Order 20 AAC 25.402 (c)(l) Plat of Wells Penetrating Injection Zone The attached map ( Exhibit 1) shows all existing wells that penetrate the injection zone in the proposed injection area. The map also shows the areal extent of the injection zone relative to the Colville River Unit boundary. The map also includes the 10cation of all proposed Alpine Oil Pool development wells. 5 e e Alpine Area Injection Order 20 AAC 25.402 (c)(2) Operators and Surface Owners within One Quarter Mile of Injection Operations Operator: ARCO Alaska, Inc. Attention: Mark Ireland P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Joe Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 6 e e Alpine Area Injection Order 20 AAC 25.402 (c)(3) Affidavit ofR. Scott Redman Regarding Notice to Surface Owners R. Scott Redman, on oath, disposes and says: 1. I am the Alpine Reservoir Engineer at ARCO Alaska, Inc., the designated operator of the Colville River Unit (which includes the Alpine Pool). 2. On , I caused copies ofthe Area Injection Order Application to be provided to the surface owner and operators of all land within a quarter mile of the unit as listed below: Operator: ARCO Alaska, Inc. Attention: Mark Ireland P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Joe Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 7 e e Alpine Area Inj ection Order 20 AAC 25.402 (c)(4) Description of the Proposed Operation The Alpine Injection Order is needed to develop the Alpine Reservoir. The expected scope ofthe current development project involves drilling 120 wells to develop 430 MMBO associated with an estimated 960 MMBO original oil in place (OOIP). Field Development Development wells will be drilled from two drill sites. Field development includes only horizontal wells on 135-acre spacing. Well layout is a direct line drive pattern configuration with rows of injectors and producers spaced 1500' apart. The wells have horizontal sections of 3000' with 1000' lateral displacement between wells along each row. Recovery Mechanism Alpine has a favorable water-oil mobility ratio that results in high areal and vertical sweep efficiency for waterflooding. Core flow studies indicate the waterflood process will leave behind high residual oil saturations in the range of 35-40%. The high residual saturations left behind by the waterflood provides an excellent tertiary recovery target. Fine grid, compositional reservoir simulations indicate that MW AG increases ultimate recovery by 10-12% at the pattern level. This high incremental MW AG recovery is achieved by reducing oil saturations in the gas swept areas and by swelling residual oil in the miscible displacement process. Miscible Injectant Supply Produced gas from the Alpine Oil Pool is the only viable source of enriching components for the miscible WAG. There are no other sources of enriching components that could be economically procured and transported to the field. Raw separator gas is not miscible with the crude oil at reservoir pressure. Enriching the produced gas by extracting rich components from fuel gas is required to attain miscibility. Extracting enriching components from fuel gas increases the volume of methane removed from the produced gas stream in order to supply fuel gas. Combining these extracted enriching components into the remaining gas stream further increases the concentration of enriching components into the injected gas. EOR Project at Field Startup In most miscible water-alternating-gas (MW AG) projects, the timing ofMW AG startup in relation to waterflood is not critical. However, at Alpine it is very important to begin 8 e e the EOR project early in the producing life of the field. lfthis is not done, the EOR reserves of the project will be significantly reduced. Proper staging of the EOR project Studies to determine the optimum development strategy for this reservoir have been undertaken. Laboratory studies of the reservoir fluids, rock properties and potential injection fluids have been consolidated in compositional reservoir simulations to understand the most efficient recovery process. These simulations indicated that in the low and modest permeability portions of the reservoir there is a clear optimum volume of water that should be injected before commencing MW AG operations. The critical water injection volume is 20% ofthe pattern hydrocarbon pore volume. If solvent injection is begun after too much water injection, the injected water will reach production wells before EOR oil can be produced. Once this occurs, adverse relative permeability will cause a drastic reduction in production rates, and EOR oil will be produced very slowly. This will greatly impact the ultimate oil recovery ofthe EOR project. Conversely, once solvent injection is begun as part ofthe MW AG process, the adverse relative permeability of water in the presence of gas will lead to low water injection rates. If solvent injection is started too early, it may not be possible to inject the desired volume of water during the economic lifetime of the pattern, again impacting ultimate oil recovery. Injectivity Issues Lower permeability rock, such as that found in the periphery of the Alpine pool, will show a significant reduction in relative permeability to water after the first slug of gas is injected. This may make it difficult to provide adequate pressure support to the offsetting producers after miscible gas is first injected. Simulation work indicates that the optimum hydrocarbon pore volume of water to inject prior to the first slug of miscible gas to be 20%. lftoo little water is injected prior to the first miscible gas it will reduce the sweep efficiency of the Miscible flood and reducing the ultimate recovery from the field. If too much water is injected prior to the first miscible gas the lowered relative permeability will slow the oil recovery and reduce the ultimate recovery of oil from the field. Adequate injection to withdrawal rates can be maintained by increasing the amount of gas injected during the MW AG cycle in those areas most affected by the relative permeability reductions. In the higher permeabilty areas of the reservoir the MW AG process will reduce the injectivity less. It is these areas which can be targeted for miscible gas injection early. Solvent Supply Solvent supply is derived solely from produced gas. Consequently, there is not enough solvent to start WAG in all patterns at once, even if that were desirable. Given this 9 e e solvent supply constraint along with the need for injecting a water pad in the modest and low permeability patterns, a staged EOR expansion schedule is critical. The field will initially start up with several injectors on gas injection and the remaining injectors on water injection. As patterns reach their water pre-injection targets, they are converted to MW AG injection. They continue on MW AG until they reach a target slug size or surveillance data indicates that the pattern efficiency is no longer competitive. MW AG expansion timing is controlled by the time required to reach the water pre- injection target. Patterns drilled early in the program with high throughput rates will be the first to reach their water pre-injection targets. Wells drilled later in the program and with lower throughputs will be the last to convert to MW AG. Disposal Operations Disposal operations, consistent with previously approved and permitted operations on (WD-02), will be confined to the Ivishak Sandstone of the Sadlerochit Group. This interval is wet in this region of the North Slope. 10 e e Alpine Area Injection Order 20 AAC 25.402 (c)(5) Description and Depth of Pool to be Affected Location The Alpine Oil Pool is located approximately 20 miles west of the Kuparuk River Unit in the Colville River delta area on Alaska's North Slope. Exhibit 1 shows the approximate outline of the pool east of the National Petroleum Reserve - Alaska (NPRA). The Colville River Unit boundary and sections for which the proposed Alpine Oil Pool rules are to apply are shown in Exhibit 2. The rules hereinafter set forth apply to the following described area and are referred to in the order as the affected area: Umiat Meridian T11N, R4E Sections 1-5 all, 7-16 all, 21-27 all. T11N, R5E Sections 1-24 all, 29-30 all. T12N, R4E Section 24,25-27,33-36 all. T12N, R5E Sections 13-15 all, 19-36 all. Age of Sediments Based on ARCO in-house palynology and micropalentology the Alpine interval is considered to be Late Jurassic in age. Pool Name The name Alpine was first applied to a Late Jurassic prospect developed by ARCO in the Colville Delta area. In 1994, the Bergschrund 1 discovery well was drilled and subsequently ARCO has used the informal name Alpine to describe the oil-bearing upper most Jurassic sandstone body. The Alpine Oil Pool is the hydrocarbon-bearing interval between 6,876 and 6,976 feet measured depth in the Bergschrund 1 well (Exhibit 3) and its lateral equivalents. The Top Alpine and Kingak E log markers bound the interval. The Top Alpine marker is defined by the minimum value on the deep resistivity curve below the Miluveach Shale. The Kingak E marker is a deep resistivity inflection point near the top of a coarsening-upward sequence in the Kingak Formation. Several Kingak markers are correlatable across the Colville River Unit. 11 · e Trap and Structure Well results and seismic data suggest the Alpine reservoir is a stratigraphic trap in which the Alpine sandstones are isolated within marine shales ofthe Kingak and Miluveach formations. Hydrocarbon accumulation is controlled by the distribution of reservoir quality sandstones. No water or gas cap has been encountered to date in the Alpine interval. Exhibit 5 is a top Alpine depth structure map based on 3D seismic data. Structural dip is to the southwest at 1 to 2 degrees. The major faults in the Alpine Oil Pool area are normal north-northwest trending, and down thrown to the west. At the Alpine level, most of the faults have small throws, generally less than 25 feet. 12 e e Alpine Area Injection Order 20 AAC 25.402 (c)(6) Description of the Formation Stratigraphy In the Colville River Delta area, the Kingak Formation contains at least three oil-bearing Upper Jurassic sandstone bodies informally named Alpine, Nuiqsut, and Nechelik (Exhibit 4). The uppermost Alpine sandstone displays the best reservoir properties of the three. The Jurassic sands were derived from a source area to the north and deposited on a shallow marine shelf in the present Colville Delta area. Each of these sandstone bodies is associated with an overall coarsening upward sequence that ranges from 200 to 300 feet thick. Each sand top is fairly sharp, suggesting rapid burial by marine mudstones of the Kingak and Miluveach intervals. Bergschrund 1, drilled in 1994, penetrated 48 feet ofoil- bearing Alpine sandstone. The Alpine sandstone tested 2,380 BOPD of 40 degree API gravity oil. The Alpine sandstone consists of very fine to fine-grained, moderate to well sorted, burrowed, quartzose sandstone with variable glauconite and clay content (Exhibit 4). Core porosity and permeability ranges are, respectively, from 15% to 23% and 1 to 160 millidarcies. The best quality sandstones are coarser grained with low matrix content. In the proposed development area, the reservoir sand body is east-west elongate, roughly 8 miles 10ng by 3 miles wide. The sand body is continuous across the development area with shale and nonpay facies only rarely present. Sand thickness from well data ranges from 30 to 110 feet. 13 e e Alpine Area Injection Order 20 AAC 25.402 (c)(8) Casing Description and Proposed Method for Testing Casing Drilling/Well Design All underground injection into the Alpine Oil Pool will be through wells permitted as service wells for injection in conformance with 20 AAC 25.005, or approved for conversion to service wells for injection in conformance with 20 AAC 25.280. Additionally, all injection wells will be constructed in accordance with 20 AAC 25.030, 20 AAC 25.412, and Conservation Order 443 (Colville River Field, Alpine Oil Pool). A typical wellbore schematic is included as Exhibit 6. The Alpine Oil Pool will be accessed from wells directionally drilled from one of two gravel pads utilizing drilling procedures, well designs, casing and cementing programs consistent with current practices in other North Slope fields. The following will preview an Alpine drilling proposal for both producing and injection wells. For proper anchorage and to divert an uncontrolled flow, 16-inch conductor casing will be drilled and cemented at least 75 feet below pad. Cement returns to surface will be verified by visual inspection. A diverter system compliant with the Commission requirements may be installed on the conductor. Surface holes will be drilled to a minimum of 1500' TVDSS for proper anchorage, prevention of uncontrolled flow, protection of aquifers, and protection from permafrost thaw and freeze back. This casing setting depth provides sufficient depth for kick tolerance, yet shallow enough to initiate build sections for high departure wells. Either 9- 5/8" or 7" surface casing strings are cemented to surface using lead slurry of lightweight permafrost cement, followed by tail slurry in a single stage. No hydrocarbon bearing intervals have been encountered to this depth in previous wells. The casing head and blowout preventer stack will be installed and tested consistent with Commission requirements. A Leak-Off Test (LOT) will be performed upon drilling no more than 50' beyond the surface casing shoe in accordance with 20 AAC 25.030(d)(2)(D). Production holes will be drilled from surface casing, encountering the top ofthe Alpine at typically 50-70 degree inclination. Production casing will be set close to horizontal and cemented within the Alpine sands. Production casing will vary in size from 7" to 3-112" OD. Top of cement will extend a minimum of 500 feet measured depth above the Alpine sands in accordance with 20 AAC 25.030(d)(4)(B). After drilling out the production casing, and prior to drilling 50' ahead into the Alpine formationy a Formation Integrity Test (FIT) will be performed (in accordance with Conservation Order No. 443 Rule 4.a) to a predetermined equivalent mud weight (EMW). Note that the Alpine reservoir fracture gradient (20 AAC 25.030(d)(2)(D» will 14 e e not be reached to minimize formation damage. Production hole will be drilled beyond the casing shoe horizontally in the Alpine sand. Lengths achieved will vary from 500' up to perhaps 8,000 ft. depending on reservoir characteristics and specific wellbore geometry. Production liners in specific cases will be required, but it is anticipated that the majority will be completed openhole. Uncemented slotted liners are included in the drilling plans on an "as-needed" basis. For example, wellbores that encounter significant shale or lost circulation intervals may receive slotted liners with external casing packers (ECP). At some point in the future coil tubing workovers may place slotted or cemented liners within the Alpine sands. Should any wells be drilled where production casing is set below rather than within the Alpine sands, production casing will be cemented across and not less than 500 feet measured depth above the Alpine. An example would be any extended reach S-shaped wells that encounter Alpine sands at inclinations below 60 degrees In addition to conventional open hole and perforated completions, additional completion designs may be presented for administrative approval by submitting and presenting data demonstrating that such alternatives are based on sound engineering principles. Casing Testing Casing-tubing annulus pressures will be monitored during injection operations in accordance with 20 AAC 2500402(d & e). Injection rates, tubing and casing pressures will be recorded on a daily basis, and abnormalities will be noted and evaluated. Significant deviations or aberrations in pressures or rates will be communicated to the Commission. Trained and qualified operators will be inspecting the wellheads and gauges as part of their daily routine. Prior to commencement of injection, each injection well will be pressure tested in accordance with 20 AAC 2504 12(c). On a frequency not to exceed every 4 years, the mechanical integrity of each well will be verified in accordance with 20 AAC 250412. In all cases, the Commission will be notified at least 24 hours in advance to enable a representative to witness the testing. In the event pressure observations or tests indicate communication or leakage of any tubing, casing, or packer, Arco will notify the Commission within 24 hours of the observation to obtain Commission approval of appropriate corrective actions. Commission approval will be received prior to commencement of corrective actions unless the situation represents a threat to life or property. Abandonment All abandonment procedures will be performed following Commission approval in accordance with 20 AAC 250.105. 15 e e Alpine Area Injection Order 20 AAC 25.402 (c)(9) Injected Fluid Analysis Miscible Injectant will be manufactured at the Alpine CPF by blending enriching fluids extracted from the fuel gas into Alpine produced gas. The initial composition of the MI will be controlled to a minimum C2+ content to assure miscibility with the oil. The expected MI content is shown below: Component MI N2 0.0048 CO2 0.0055 Cl 0.6450 C2 0.1200 C3 0.1446 C4 0.0670 C5 0.0101 C6 0.0021 C7-8 0.0009 Total 1.0000 Initially, Beaufort Sea water will be injected in the Alpine field with Alpine MI. This sea water has been tested and found to be compatible with the Alpine formation. Later in the life ofthe field, after water breakthrough occurs, Alpine produced water will also be re- injected in the Alpine formation. Prior to injecting produced water into the Alpine Field, tests will be run to assure that the Alpine produced water is compatible with the Alpine formation. 16 e e Alpine Area Injection Order 20 AAC 25.402 (c)(lO) Estimated Pressures The maximum MI injection pressures available at the plant will be 4500 psi. Due to pressure losses in the distribution system, the actual maximum wellhead pressures will vary. Injection wells may also be choked to avoid exceeding injection targets. Wellhead injection pressures are expected to range from 3600 psi to 4300 psi. 17 e e Alpine Area Injection Order 20 AAC 25.402 (c)(ll) Fracture Information The State of Alaska has determined there are no fresh water aquifers within the Colville River Unit. Consequently, injected fluids cannot breach the Alpine Oil Pool and threaten 10cal fresh water sources. Additionally, rock mechanics studies suggest injected fluids will be wholly contained within the Alpine Oil Pool. Sufficient fluid samples and log derived formation water salinities have been presented to the State of Alaska and the federal Environmental Protection Agency (EP A) to determine there are no Underground Sources of Drinking Water (USDW) in the Colville River Unit. Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Permit Application, Appendix D, previously submitted to the Commission in September 1997. Rock mechanics and fracture analysis confirm that although bottom-hole injection pressures will routinely exceed the formation parting pressure during enhanced recovery operations all injected fluids will remain trapped within the Alpine Oil Pool by surrounding shales. Dipole sonic data from WD-02 and Bergschrund #1 has been analyzed by Arco Exploration and Production Technology and Geo-Quest staffto determine fracture gradients and rock mechanics properties. Additionally, onsite surveillance reports provide input on fracture extension pressures encountered in the field. The Alpine Oil Pool fracture gradient has been measured at 0.60 psi/ft. This was determined by a data frac performed on Alpine #lB preceding a fracture treatment in 1996. The surface measured Instantaneous Shut-In Pressure (ISIP) was 1750 psi with diesel displaced to the perfs. A confirming fracture gradient was observed during oil re- injection operations upon the conclusion of testing CD2-35. Pressure measurements taken with gauges installed immediately above the packer measured an initial fracture extension pressure of 4200 psi, or 0.6 psi/ft. The Miluveach formation sits atop the Alpine Oil Pool, and provides an approximately 120' upper boundary to fracture growth. This competent shale provides a stress contrast of 1000 to 2000 psi above the Alpine fracture extension pressure. The Upper Kingak formation provides the fluid seal immediately below the base of the Alpine reservoir. This laterally extensive interval averages approximately 150' thick within the productive Alpine Oil Pool1imits. The Upper Kingak is mainly composed of dense clay-rich siltstone. Log analysis confirms this interval provides a minimum stress contrast of 500 psi above the Alpine fracture extension pressure. 18 e e Fracture modeling using Stimplan (i.e., Nolte/Smith's pseudo 3-D fracture model) confirms fracture heights are established very early in the operation and remain entirely contained within the Alpine interva1. Model runs in a 39'thick Alpine interval for approximately 2 years with water injection rates of 10 bpm project gross fracture height to reach 50'. Such a fracture would only breach beyond the Alpine formation by 11'. This estimate is conservative since projected injection rates do not exceed 5 bpm. Under comparable constraints the same models predicts 5 bpm generated height growth to reach 45', or 6' into adjacent shales (see Exhibit 7). This estimate will be overly conservative for injection of gas or MI. Such compressible, low viscosity fluids will generate significantly less fracture growth. Conservative current models such as Stimplan assume 'worst case' single, planar, vertical fractures that result from relatively short duration injection (approximately 200,000,000 ga1.). These models were developed for short duration fractures into less ductile, brittle "hard rock" formations. Since dendritic fractures, disaggregation (i.e., destruction of the rock matrix) and particle invasion ofthe rock matrix are not captured by these models, they conservatively represent the impacts of years oflong term injection adjacent to "soft" shaley formations. Including the effects of dendritic fractures, etc. increases fluid storage thereby reducing height and length projections. 19 e e Alpine Area Injection Order 20 AAC 25.402 (c)(12) Formation Fluid Salinity Calculations In the Alpine project area only the Nechelik #1 well has been logged from surface through the injection zone. No clean sands were encountered above the confining zone; however, the Alpine #1 well did cut some thin Albian sands at 5150-5204 feet, and Bergschrund #1 found a thin shelf sand at 4220 feet. Salinity calculations made on available intervals resulted in the following. · Bergschrund # 1 (4220 feet) 15,000 ppm NaCl eq. · Alpine # 1 (5150-5204 feet) 15,000 ppm NaCl eq. · Nechelik #1 (Sag River Formation) 18,000 ppm NaCl eq. · Nechelik #1 (Ivishak Formation) 17,000 ppm NaCl eq. The methodology used and results obtained from salinity calculations on the Albian/Nanushuk Shelf sand stringers (Alpine #1 and Bergschrund #1), Sag River, and Ivishak Formations (Nechelik #1 well) are as follows. The calculations use the standard Archie correlation and log derived data to obtain an Rwa value using the following formula: Rwa = (porosity) ill (Rt) / a ........... with the following definitions: Rwa Porosity Rt Resistivity of water necessary to make a zone 100 % wet Porosity in decimal from logs Formation resistivity from logs Cementation exponent Assumed to be 1.0 per the Archie correlation m a The cementation exponent is the variable ofleast certainty. The best source for determining this value is from special core analysis (SCAL) when available. No SCAL is available for the Albian interval; however, such data does exist for analogous fine to very fine grain sand in the area. This data has yielded: Alpine section SCAL from the Alpine #1 well m = 1.55 20 e e Sag River SCAL as documented in ARCO TSR 95-46, internal report m = 1.6 The following exponents will be used in these salinity calculations. Shallow intervals (4000- 5000 feet) Sag River Formation Ivishak Formation m = 1.6 m = 1.7 m = 1.8 · Nanushuk Shelf Sand: (Bergschrund #1 well depth 4220 feet) This shelf sand is evident in two wells at approximately 4200 feet subsea. Rt = 4.0, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The calculation yields an Rwa equal to 0.356. Using Schlumberger Chart Gen-9 and a formation temperature of80 degrees F, gives a salinity of 15,000 ppm NaCl equivalent. · Albian Interval: (Alpine #1 well depth 5150-5204 feet) There is a collection of thin sands in this well and a complete set of logs is available. Rt is taken from the shallow MWD tool because of minimum exposure time to invasion and superior vertical resolution in three-foot thick beds. Porosity comes from the density 10g. Rt = 3.2, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The Calculation yields an Rwa equal to 0.293. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100 degrees F, gives a salinity of 15,000 ppm NaCl equivalent. · Sag River Formation: (Nechelik #1 well depth 8432-8480 feet) This is a thick, clean, uniform sand interval with a complete set of logs. Rt = 1.9, Raw density = 2.32, m = 1.7, Porosity = (2.65-2.32) / (2.65-1.0) = 0.20 The calculation yields an Rwa of 0.145 and with a formation temperature of 165 degrees F, produces a salinity value of 18,000 ppm NaCl equivalent. · Ivishak Formation: (Nechelik #1 well depth 9420-9460 feet) This 10wer sand member has the lowest resistivity and greatest SP excursion. 21 e e Rt = 3.3, Raw density = 2.35, m = 1.8, Porosity = (2.65-2.35) / (2.65-1.0) = 0.18 The calculated Rwa equals 0.15 and with a formation temperature of 185 degrees F, a salinity of 17,000 ppm NaCl equivalent is obtained rrom the Schlumberger chart. Water Sample Analyses The following water samples were obtained from drill stem and production tests in the general Colville Delta area. · Colville #1 well 7922 feet · 14 miles Northeast · 22,485 mg/l TDS (tested) Shublik Formation · Colville #1 well 9073 feet · 14 miles Northeast · 24,004 mg/l TDS (tested) Lisburne Formation · Kalubik #1 well 5050-5250 feet Albian Interval · 17 miles Northeast · Flowed 151 barrels to surface · 24,300 mg/l TDS (average oftests) · Kalubik Cr. #1 well 9047-9188 Lisburne Formation · 21 miles East · Flowed 325 barrels of water · 21,847 mg/l TDS (tested) · Mukluk well 7490-7520 Ivishak Formation · 23 miles North · Flowed 984 barrels of water · 11,000 ppm chloride tested · 18,150 mg/l TDS (calculated) · Mukluk well 8145-9860 Lisburne Formation · 23 miles North 22 e e · Flowed 1750 barrels of water · 11,000 ppm chloride tested · 18,500 mg/l TDS (calculated) Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Permit Application, Appendix D, previously submitted to the Commission in September 1997. 23 e e Alpine Area Injection Order 20 AAC 25.402 (c)(13) Aquifer Exemption No underground sources of drinking water (USDW) have been identified within the Colville River Unit area. Since there are no USDW's at Alpine, an aquifer exemption per 20 AAC 25.440 is not applicable. The Colville River Unit Area includes; Township UN Range 4E - (Umiat Meridian) Sections 1-5 all, 7-16 all, 21-27 all. Township 11N Range 5E - (Umiat Meridian) Sections 1-24 all, 29-30 all. Township 12N Range 3E - (Umiat Meridian) Sections 25-27 all, 34-36 all. Township 12N Range 4E - (Umiat Meridian) Sections 20-21 all, 22 excluding portion in Survey USS 9502 (2), 23-27 all, 28-32 excluding portions offshore, 33-36 all. Township 12N Range 5E - (Umiat Meridian) Sections 1-36 all. Township 13N Range 5E - (Umiat Meridian) Sections 9-10 all, 15-22 all, 26-36 all. 24 e . Alpine Area Injection Order 20 AAC 25.402 (c)(14) Incremental Hydrocarbon Recovery Miscible Injectant Criteria The initial reservoir pressure at Alpine is about 3200 psi. Reservoir simulations indicate that the reservoir pressure will decrease about 200 psi during the first several years of production. The Miscible Injectant will be designed to be miscible 100 psi below the projected reservoir pressure. The initial Miscible Injectant composition is designed to be fully miscible with reservoir oil at a reservoir pressure of 2900 psi. Fine Grid Compositional Model Results Fine grid, fully compositional models were developed to estimate the recovery for different development options. The models indicated that Miscible Water Alternating Gas could increase individual pattern recoveries by 10-12% OOIP over waterflooding. Full Field Model Results The recovery estimates for both the original waterflood/gas cycling plan of development and the new enriched miscible gas plan of development come from state-of-the-art reservoir simulations with a compositional simulator. The most current simulations for the full-field Alpine model indicate an ultimate recovery of about 329 MMBO for the original waterflood plan of development and 429 MMBO for the proposed enriched miscible gas plan of development. Thus, the proposed plan of development is expected to increase ultimate recovery by an additional 1 00 MMBO over the original pIan of development. This equates to an improvement in recovery of approximately 11 % of the OOIP. 25 e . Alpine Area Injection Order Recommended Conclusions ARCO Alaska, Inc., as CRU Operator, respectfully proposes that the Commission make the following conclusions. 1. The Alpine MW AG project involves the application of a tertiary enhanced oil recovery method in accordance with sound engineering principles. 2. The Alpine Miscible WAG project is reasonable and expected to result in a significant increase in the amount of crude oil that ultimately will be recovered. 3. The Alpine Miscible WAG project will recover oil from areas not affected by previous EOR operations. 4. The Alpine Miscible WAG process must be started early in the life of the field to maximize ultimate recovery due to productivity impacts after water breakthrough and a limited MI supply generated from oil production. 26 · e Alpine Area Injection Order Requested Decisions ARCO Alaska, Inc., as CRU Operator, respectfully proposes that the Commission issue an injection order authorizing the underground injection of water and miscible enriched natural gas for enhanced oil recovery in the Alpine Pool. 27 EXHIBIT 1 PROPOSED ALPINE DEVELOPMENT WELLS 'XE FIOR D 1 . 1A it TEMPTATION 1 e 1 . NANUK 1 .. .. 1 " ::: 8000' -- FIORD 2 II 3- RORD Alpine Oil P EXHIBIT 2 " 001 Section B . oundarles 5 4 32· 1 6 5 " . . )'..PINE 2 7 8 9 10 11 12 7 - 111 17 1. 15 14 13 19 20 21 22 24 30 29 28 27 26 I/' EXHIB BERGSCHRUND 1 o ¡:: rJJ 1/) 1 T ..J:lÞINE EXHIB PINE OIL POOL o R Depth 150 1 T ,,"P1INB t . i . 't 6840 .' .... . (. .. ==< ; . < !> .. :::::::- / 68€ú , :< "- \ - <-> _:--.. -- - 68€ú } ( 6900 ) ~ . .~ 69 ............... ,/- -) ......) ~ .. 1~ ': ~ V ¿ \ ¡~ ; <) \ . E dark bioturbated ~ A Top ne Sandstone, v'f-f grained, well burrowed, a:> 6940 Siltstone and sllt-vf bu rrowed 6900 6900 \..f HRU ND 1 EXHIBIT TOP ALPINE DEPTH STRUCTURE u o . ..... INE 1 ~ N ~ 1 ~ _J ~- ~ .- ~ .. TOC +/- 500': above Alpin~ e e Colville River Field Exhibit 6 -Injector Completion Schematic 4-1/2" Camco "A-1" SSSV (2.125"ID) in DB-6 Lock (3.812" ID) @ 1,000' MD 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2400' TVD cemented to surface 4-1/2" 12.6 ppf L-80 IBT Mod. tubing (Jet Lube Run'n'Seal) Packer Fluid mix: 9.2 ppg KCI Brine with EC-1124A and 1200' diesel cap 1 - Baker S-3 Packer (3.875" ID) 2 - 4-1/2" joints (2) blank tubing 3 - HES "XN" (3.725" ID) LN 4 - 4-1/2" joint tubing 5 - 4-1/2" WLEG - . - - . - - - . - - - - . - . - - . - - - - . . . . . . . . - . . . . . . . . . 6-1/8" Open hole ... -. ... - --.. - ----.---.-..-.- ---. .... .... 7" 26 ppf L-80 BTC Mod Production Casing @ 90 deg . . Exhibit 7 - Stimplan Fracture Growth Model- 5 BPM Stress (psi) · ... .. · .. . ......................-........ . ¡ . , : , .. ..... r·.... , , , , ¡ , · · , '~""'J"""~'."'.l..... . . . . 'o4 . ,. , · I . , . , , · , · , , . , . , . , . , . · , · , , , " . " . .-1 ...... ...... I............~. · 'I . , , . , . . , . , , , , : I : , , , , , , ¡ ¡ ¡ , . , · " . · 'I . , , , , , , ..¡.......i......"..·..+··....¡. . · ! . . . 3500 4000 4500 5000 5500 .....-........ . I ¡ I 5000 2000 1000 500- .¡¡¡ 8; \!! 200 - :;, en en Q) 100 iï. .... Q) z 50 20 10 5.0 2"0 5.0 ARCO Exploration and Production Technology Max Width 0.09 in c ~ ~ 0.0 At Closure · . . 6700 .................... ~........ ....... .... .~... .... .............:......... .......... 6800 ........................._........ ............................... ..III.......... ........ ... · , · , : : , , · , · , , , , . , . = : · , · , · , , , , , ~ :I'! ........................¡........ ............................... ....... .. II........ ....... ... · I ' : : ; · . , · . , , , , , , , , , , , , . , . , · , , · , . , , . · . . · . . , , . · , , · , , · , , · , , ..................~................-Io.................:;.................. · · , · , , ¡ , · · ! ..................t·· ..............-10................ +...... ........... · ! 6900 7000 7100 500 1000 1500 Fracture Penetration (ft) Alpine WD-02 Water Injection 10 2b 100 2(ÌO 50 ~ *", 5ÚO 1 doo 20bo 5doo 1000020000 50000 Time (min) 200boo 50doDO . . Alpine Area Injection Order 20 AAC 25.402 (c)(3) Affidavit of R. Scott Redman Re2ardine Notice to Suñace Owners R. Scott Redman, on oath, deposes and says: 1. I am the Alpine Reservoir Engineer at ARCO Alaska, Inc., the designated operator of the Colville River Unit (which includes the Alpine Pool). 2. On September 8, 1999, I caused copies ofthe Area Injection Order Application to be provided to the surface owner and operators of all land within a quarter mile of the unit as listed below: Operator: ARCO Alaska, Inc. Attention: Mark Ireland P. O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mike Kotowski P. O. Box 107034 Anchorage, AK 99510 Kuukpik Corporation Mr. Joe Nukapigak PO Box 187 Nuiqsut, Alaska 99789-0187 ~,~Af/~ R. Scott Redman STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) SUBSCRIBED AND SWORN to before me this 13th day of September, 1999. )Û~"- )i' ?l ~~t (~ NOTARY PUBLIC IN AND FOR ALASKA ~N,~\\\"urlll1l~'1I ~~' '"f, Mb"~ ~ ..........~/IS' ~,z ,&~, ...... ....~t<'~ ~ ..:1)~ ., . NO'I~ï'" '. ~ ::c: ~:# =- : .': :: ~ ~ . "" . .J ,,' ~ .: - =: þ\ PUl\¡;..lC .:~ ~ ," " i:::: ..'~~ ."" .....~ 4.."",.,. ~ 'Y}¡~~;:"""" ",C"'.$S" ~>" I," ("" ..\..\"~~~,,, -?~. ,~ 'r ::,ù~.·' '1.~'i/lim ~\\\\\~,. My Commission Expires: ) ().-¡ Lf-7' 7 7