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CO 443
e e Image Project Order File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~ Order File Identifier Organizing (done) o Two-sided 1111111111111111111 o Rescan Needed 1111111111111111111 RES CAN ~olor Items: ÍøireYScale Items: DIGITAL DATA OVERSIZED (Scannable) o Maps: tz'6ther Items Scannable by 1 a Large Scanner o Diskettes, No. D Other, NolType: D Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: o Logs of various kinds: NOTES: BY: ~ Date #/07 o Other:: Project Proofing Isl mp 11/1111111111111111 BY: ~ Date I /c¡fojo7 Is/ Y11P Scanning Preparation BY: = TOTAL PAGES ~ faft> (Count does not include cover stì t) /s/ Date: + Production Scanning Stage 1 Page Count from Scanned File: 3.if2.+ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES BY: ~ Date:II~"/07 1111111111111111111 NO /s/ rv1f NO Stage 1 BY: If NO in stage 1 page(s) discrepancies were found: YES Maria Date: /s/ 11111111111I11 IIII1 Scanning is complete at this point unless rescanning is required. ReScanned 1111111111111111111 BY: Maria Date: /s/ Comments about this file: Quality Checked 11111111111I 1111111 10/6/2005 Orders File Cover Page. doc INDEX CONSERVATION ORDER 443 COLVILLE RIVER FIELD 1. October 09, 1998 ARCO Application for Alpine Pool Rules 2. October 16, 1998 Public Hearing Notice, Affidavit of publication, e -mail listing 3. November 09, 1998 Fax from ARCO re: Proposed Oil Pool Rules 4. December 03, 1998 Hearing Documents, ARCO request for Alpine Oil Pool Rules with revised application 5. December 03, 1998 Public Hearing Sign -In Sheet 6. December 03, 1998 Public Hearing Transcript 7. December 09, 1998 Requested documentation from ARCO 8. December 16, 1998 ARCO ltr Re: Alpine Pool Rules 9. December 16, 1998 DNR ltr Re: Alpine Pool Rules 2004 Well testing waiver application and approval February 12, We 1 test Y g pp pp roval 11. May 28, 2004 ConocoPhillips request for exception to 20 AAC 25.055 12. June 29, 2004 ConocoPhillips revised request for exception to 20 AAC 25.055 13. November 17, 2009 BPXA request for clarification of Rule 5 of Order CO 443 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: THE APPLICATION OF ARCO ALASKA, INC. to classify the Alpine Oil Pool and establish rules for development. ) Conservation Order No. 443 ) ) Colville River Field ) Alpine Oil Pool March 15, 1999 IT APPEARING THAT: 1. By letter dated October 9, 1998, ARCO Alaska, Inc. ("ARCO") requested a public hearing to present testimony to define the Alpine Oil Pool and establish rules for development. 2. The Commission published notice of public hearing in the Anchorage Daily News on October 16, 1998. 3. A hearing concerning the matter of the applicant's request was convened in conformance with 20 AAC 25.540 at the Commission's offices, 3001 Porcupine Drive, Anchorage, Alaska 99501 at 9:00 a.m. on December 3, 1998. FINDINGS: 1. The Alpine Oil Pool ("AOP") is located adjacent to the National Petroleum Reserve- Alaska, within the Colville River Delta, on Alaska's North Slope. 2. Working interest owners are ARCO, Anadarko Petroleum Corporation and Union Texas Alaska, LLC. Landowners are the State of Alaska and the Arctic Slope Regional Corporation. The owners have agreed to voluntarily integrate their respective interests to provide for the unitized management, development and operation of the pool under the Colville River Unit Agreement. ARCO is the operator of the Colville River Unit. 3. The currently known productive limits of the AOP lie entirely within the Colville River Unit. 4. The AOP was discovered in 1994 with the drilling of the Bergschrund #1 exploratory oil well. ARCO has subsequently delineated the pool with 11 exploratory wells, two development wells and a 3-D seismic survey. 5. The AOP may be defined between 6876 feet and 6976 feet measured depth in the Bergschrund #1 well, which appears to contain a typical and representative stratigraphic section of the reservoir. 6. The AOP is contained within the Alpine Sandstone. Conservation Order No. ,. Alpine Oil Pool March 15, 1999 . Page 2 7. The Alpine Sandstone is a Late Jurassic-aged, informal member of the Kingak Formation. It is stratigraphically the highest sandstone unit within the Kingak Formation in the Colville Delta area. 8. The Alpine Sandstone is an Ellesmerian, shallow marine sand deposited on a southerly prograding shelf, elongated in an east-west direction. The interval consists of very fine to fine-grained, moderate to well sorted quartzose sandstone with variable glauconite and clay content. Bedding is almost horizontal, dipping about one to two degrees to the southwest. Core porosity and permeability ranges are 15% to 23% and 1 to 160 millidarcies, respectively. 9. The AOP appears stratigraphically trapped by pinch-out of Alpine Sandstone into time equivalent shales of the Kingak Formation. 10. No oil-water or gas-oil contacts have been observed to date in the AOP. 11. Faulting currently delineated in the AOP is minor, consisting of several northwest trending, down the west, normal faults with throws averaging less than 30 feet. 12. None of the stratigraphic and structural discontinuities currently identified in the AOP appear to have caused any compartmentalization of the reservoir. 13. In addition to the AOP, ARCO has identified several other oil-bearing sandstone intervals with possible productive potential in the Colville River Delta area. ARCO plans to evaluate the commercial productivity of these intervals when developing the AOP. 14. ARCO proposes to dispose of drilling waste in the annuli of wells authorized by the Commission for that purpose under 20 AAC 25.080. 15. Typical AOP development wells will have surface casing set in the basal shales of the Upper Cretaceous Schrader Bluff Formation and intermediate casing set in shales of the Lower Cretaceous Miluveach Formation. 16. The intermediate casing annulus of a typical AOP well will be in contact with approximately 1800 vertical feet of the Upper Cretaceous Seabee Formation, a predominately mudstone interval with silt and sandstone interbeds. The sandstones are very fine to fine-grained and range from unconsolidated to consolidated. 17. Over 1000 feet of shales and siltstones of the Schrader Bluff Formation will provide an upper barrier for annular disposal. Marine shales and claystones of the Lower Cretaceous Torok Formation will provide a lower barrier. 18. Calculated water salinity ranges from 15,000 to 18,000 milligrams per liter (mg!l) total dissolved solids (TDS) throughout the Cretaceous and older stratigraphic section in the Colville Delta area. Water samples collected from drill stem and production testing of several wells in the Colville Delta area yielded 18,500 to 24,000 mg!l TDS. 19. The U.S. Environmental Protection Agency ("EP A"), in compliance with the provisions of the Safe Drinking Water Act (SDW A), has authorized ARCO to inject non-hazardous industrial waste through class I injection wells at the Colville Field ofthe Colville River M:\co443.doc Conservation Order NO.4_ Alpine Oil Pool March 15, 1999 . Page 3 Unit. (EP A Alpine Class I well pennit, dated February 3, 1999.) 20. Petrophysical analysis indicates that thick sections of the Seabee Fonnation have less mechanical strength than the basal Schrader Bluff Fonnation. 21. Data available at this time indicate that annular disposal into the Seabee Fonnation can occur in AOP development wells, which have been authorized for that purpose by the Commission under 20 AAC 25.080, without causing fTactures proximal to the surface casing shoe. 22. Development drilling to the Alpine Oil Pool is projected to begin in the first quarter of 1999. Commercial production is expected to begin in June 2000. 23. ARCO plans to drill a large number of high departure horizontal wells, with interwell spacing dictated by reservoir perfonnance. 24. ARCO proposes to establish the Alpine Participating Area within the Colville River Unit next year. ARCO will seek additional pool rules regarding drilling and completion practices, production practices, reservoir monitoring and other topics, as appropriate, following the completion of initial development wells and prior to commercial production. 25. Initial reservoir pressure of the AOP is 3175 psig at 6864 feet TVDss. Average reservoir temperature is 160° F. Fluid samples indicate the reservoir is undersaturated with a bubble point pressure of2454 psig. Solution GOR is 850 SCF/STB. Oil gravity and viscosity at reservoir conditions are 40° API and 0.46 cp., respectively. 26. Volumetric estimates of original oil-in-place range from 900 to 1100 MMSTB. 27. ARCO has divided the scope of currently planned AOP development into two phases. Phase one provides for 50 wells and phase two for 42 additional wells. Under the plan, total development will include 32 horizontal wells and 60 vertical wells (through the reservoir), with well spacing of 275 acres per horizontal well and 160 acres per vertical well. ARCO may revise the development plan following assessment of miscible-water- alternating-gas (MW AG) for EOR throughout the field. Under a revised MW AG development plan, well spacing could be reduced to 135 acres per well, with as many as 140 wells throughout the field, in order to take full advantage of the MW AG process. 28. ARCO'S plan for secondary oil recovery includes water and gas injection, beginning concurrentlywith production startup. ARCO will conduct studies to optimize depletion plans based on initial production and injection perfonnance, and will consider the viability of miscible gas injection. 29. ARCO proposes to measure reservoir pressure periodically in injection wells with static measurements and other industry standard techniques at a datum level of 7000' TVDss. ARCO does not propose to take pressure measurements in producing horizontal wells because production models show these wells take an inordinately long period of time to stabilize. 30. ARCO requests authorization to test production wells less frequently than once per month as required under statewide regulation, 20 AAC 25.230. M:\co443.doc Conservation Order NO.4' Alpine Oil Pool March 15, 1999 . Page 4 31. The Alaska Department of Natural Resources requests that a minimum of two well tests per month per well be required as the initial testing frequency in order to ensure that the well tests accurately represent oil, gas and water production rates and production volumes from the various tracts that comprise the AOP. (Kenneth A. Boyd, letter dated Dec. 16, 1998) 32. Reservoir model simulation will be used to allocate production to participating tracts in the Colville River Unit. Accurate well test data is necessary to calibrate the reservoir model. CONCLUSIONS: 1. Defining the AOP and establishing rules for initial development is appropriate at this time. 2. The Alpine Oil Pool is not completely delineated at this time. 3. Recovery methods to enhance and maximize ultimate recovery from the AOP are currently being evaluated. 4. Statewide spacing requirements under 20 AAC 25.055, which limit drilling one well per government quarter section, may not provide adequate flexibility in well locations to optimally develop the AOP. 5. There are no freshwater aquifers in the Colville River Unit. . 6. The depth and thickness of the proposed receiving zone and confining zone are sufficient to demonstrate confinement of drilling waste. 7. Exception to the gas-oil ratio limitations of 20AAC 25.240 is appropriate provided a pressure maintenance project is begun within six months of regular production and the requirements of 20 AAC 25 .240( c) are met. 8. Reservoir pressure should be measured in wells using standard industry practices on a regular basis to manage production and monitor reservoir performance. 9. A minimum of two well tests per month will help ensure that accurate well test data is available for reservoir management and production allocation. NOW, THEREFORE, IT IS ORDERED THAT the rules hereinafter set forth, in addition to the statewide requirements under 20 AAC 25, apply to the following affected area referred to in this order. Umiat Meridian TllN R4E Section 1,2,3,4,5, 7, 8,9, 10, 11, 12, 13, 14, 15, 16,21,22,23,24,25,26, 27. T11N R5E Sections 1,2,3,4,5,6, 7, 8,9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19,20,21, 22,23,24,29, 30. T12N R4E Sections 24, 25, 26, 27, 33, 34, 35, 36. M:\c0443.doc Conservation Order NO.4' Alpine Oil Pool March 15, 1999 . Page 5 T12N R5E Sections 13, 14, 15, 19,20,21,22,23,24,25,26,27,28,29,30,31,32,33, 34, 35, 36. Rule 1 Field and Pool Name The field is the Colville River Field. Hydrocarbons underlying the affected area within the defmed pool interval ofthe Kingak Fonnation constitute a single oil and gas reservoir called the Alpine Oil Pool. Rule 2 Pool Defmition The Alpine Oil Pool is defined as the accumulation of hydrocarbons common to and correlating with the interval between the measured depths of 6876 feet and 6976 feet in the Bergschrund No. 1 well. Rule 3 Well Spacing Development wells may not be completed within 500 lineal feet of another Alpine Oil Pool development well nor closer than 500 feet from the exterior boundary of the affected area. Rule 4 Drilling and Completion Practices (a.) After drilling no more than 50 feet below a casing shoe set in the Alpine Oil Pool, a fonnation integrity test must be conducted. The test pressure need not exceed a predetennined pressure. (b.) Casing and completion designs may be approved by the Commission upon application and presentation of data that demonstrate the designs are appropriate and based upon sound engineering principles. (c.) Pennit(s) to Drill deviated wells within the Alpine Oil Pool shall include a plat with a plan view, vertical section, close approach data and a directional program description in lieu of the requirements of20 AAC 25.050(b). (d.) A complete petrophysical log suite acceptable to the Commission is required from below the conductor to TD for at least one well on each drilling pad in lieu of the requirements of 20 AAC 25.071(a). The Commission may, in its discretion, require additional wells on a pad to be logged using a complete petrophysical log suite. Rule 5 Automatic Shut In Equipment (a.) All production wells must be equipped with a fail-safe automatic surface safety valve (SSV) and a surface controlled subsurface safety valve (SSSV). (b.) Injection wells must be equipped with a double check valve arrangement. (c.) Safety Valve Systems (SVS's) must be tested on a six-month frequency. Sufficient notice must be given so that a representative of the Commission can witness the tests. (d.) Subsurface safety valves may only be removed after demonstrating to the Commission that the well is not capable of unassisted flow of hydrocarbons. Sufficient notice must be given so that a representative of the Commission can witness the tests. M:\co443.doc Conservation Order No. '" Alpine Oil Pool March 15, 1999 . Page 6 Rule 6 Reservoir Pressure Monitoring (a.) Prior to regular injection, an initial pressure survey shall be taken in each injection well. (b.) A minimum of six bottom-hole pressure surveys shall be measured annually. Bottom-hole surveys in paragraph (a) may fulfill the minimum requirement. (c.) The reservoir pressure datum shall be 7000 feet TVD subsea. (d.) Pressure surveys may consist of stabilized static pressure measurements at bottom-hole or extrapolated from surface, pressure fall-off, pressure buildup, multi-rate tests, drill stem tests, and open-hole fonnation tests. (e.) Data and results from pressure surveys shall be reported annually on Fonn 10-412, Reservoir Pressure Report. All data necessary for analysis of each survey need not be submitted with the Fonn 10-412 but shall be made available to the Commission upon request. (f.) Results and data from special reservoir pressure monitoring tests or surveys shall also be submitted in accordance with part (e) of this rule. Rule 7 Gas-Oil Ratio Exemption Wells producing from the Alpine Oil Pool are exempt from the gas-oil-ratio limits of20 AAC 25.240(b) so long as the provisions of20 AAC 25.240(c) apply. Rule 8 Reservoir Surveillance Report A surveillance report is required after one year of regular production and annually thereafter. The report shall include but is not limited to the following: (a.) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. (b.) Voidage balance by month of produced fluids and injected fluids. (c.) Analysis of reservoir pressure surveys within the pool. (d.) Results and where appropriate, analysis of production log surveys, tracer surveys, and observation well surveys. (e.) Future development plans Rule 9 Well Testing (a.) All wells must be tested at least twice per month. (b.) The operator shall optimize stabilization and test duration of each test to obtain a representative test. (c.) The operator shall record well and field-operating conditions appropriate for maintaining an accurate field production history. (d.) The operator shall install and maintain test separator meters and gas system meters in confonnance with the API Manual of Petroleum Measurement Standards. (e.) The operator shall maintain records to allow verification of approved production allocation methodologies. M:\co443.doc Conservation Order NO.4. Alpine Oil Pool March 15, 1999 - Page 7 Rule 10 Administrative Action Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles. DONE at Anchorage, Alaska and dated March 15, 1999. ~~ Robert N. Christenson, P.E., Chainnan ~~~. Camillé Oechsli, Commissioner ~ AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the lO-day period. An affected person has 30 days from the date the Commission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Commission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). M:\co443.doc . ~ :~ ifi·\~ 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 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 . ~. 3-11-~O¡. v.c. 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 AMERICAN PETR INST STAT SECT JEFF OBERMILLER 1220 L ST NW WASHINGTON DC 20005 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 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON DC 20585 US GEOL SURV LIBRARY NATIONAL CTR MS 950 RESTON VA 22092 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 e TECHSYS CORP BRANDY KERNS PO BOX 8485 GATHERS BURG MD 20898 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 OPERATIONS SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY OK 73102-5605 IOGCC POBOX 53127 OKLAHOMA CITY OK 73152-3127 CH2M HILL J DANIEL ARTHUR PE PROJ MGR 502 S MAIN 4TH FLR TULSA OK 74103-4425 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 OIL & GAS JOURNAL LAURA BELL POBOX 1260 TULSA OK 74101 R E MCMILLEN CONSULT GEOL 205 E 29TH ST TULSA OK 74114-3902 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 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 e e 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 e e EXXON EXPLOR CO LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON TX 77210-4778 CHEVRON USA INC. 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RAMP 6330 W LOOP SOUTH BELLAIRE TX 7740~ PHILLIPS PETR CO PARTNERSHIP OPRNS JERRY MERONEK 6330 W LOOP S RM 1132 BELLAIRE TX 77401 TESORO PETR CORP LOIS DOWNS 8700 TESORO DR SAN ANTONIO TX 78217 INTL OIL SCOUTS MASON MAP SERV INC POBOX 338 AUSTIN TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON CO 80127 AMOCO PROD CO C A WOOD RM 2194 POBOX 800 DENVER CO 80201-0800 C & R INDUSTRIES, INC. KURT SALTSGAVER 1801 BROADWAY STE 1205 DENVER CO 80202 NRG ASSOC RICHARD NEHRING POBOX 1655 COLORADO SPRINGS CO 80901-1655 e e ROBERT G GRAVELY 7681 S KIT CARSON DR LITTLETON CO 80122 GEORGE G VAUGHT JR POBOX 13557 DENVER CO 80201 AMOCO PROD CO LIBRARY RM 1770 JILL MALLY 1670 BROADWAY DENVER CO 80202 JERRY HODGDEN GEOL 408 18TH ST GOLDEN CO 80401 RUBICON PETROLEUM, LLC BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE ID 83702 TAHOMA RESOURCES GARY PLAYER 1671 WEST 546 S CEDER CITY UT 84720 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 . e 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 PACIFIC WEST OIL DATA ROBERT E COLEBERD 15314 DEVONSHIRE ST STE D MISSION HILLS CA 91345-2746 76 PRODUCTS COMPANY CHARLES BURRUSS RM 11-767 555 ANTON COSTA MESA CA 92626 WATTY STRICKLAND 1801 BLOSSOM CREST ST BAKERSFIELD CA 93312-9286 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 e 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 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 AX 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 AX 99501 YUKON PACIFIC CORP JOHN HORN VICE CHM 1049 W 5TH AV ANCHORAGE AK 99501-1930 e e DUSTY RHODES 229 WHITNEY RD ANCHORAGE AX 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 AK 99501 PRESTON GATES ELLIS LLP LIBRARY 420 L ST STE 400 ANCHORAGE AX 99501-1937 ALASKA DEPT OF LAW ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE AK 99501-1994 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 AK JOURNAL OF COMMERCE OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B STREET STE #210 ANCHORAGE AK 99503-5911 e e 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 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 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 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 RUSSELL DOUGLASS 6750 TESHLAR DR ANCHORAGE AK 99507 e DEPT OF NATURAL RESOURCES DIV OF OIL & GAS JULIE HOULE 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS TIM RYHERD 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 STU HIRSH 9630 BASHER DR. ANCHORAGE AK 99507 US BUREAU OF LAND MNGMNT ANCHORAGE DIST OFC DICK FOLAND 6881 ABBOTT LOOP RD ANCHORAGE AK 99507 THOMAS R MARSHALL JR 1569 BIRCHWOOD ST ANCHORAGE AK 99508 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 RESOURCE STUDIES AK OCS REGN KIRK W SHERWOOD 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4302 e US BLM AK DIST OFC RESOURCE EVAL GRP ART BONET 6881 ABBOTT LOOP RD ANCHORAGE AK 99507-2899 CASS ARlEY 3108 WENTWORTH ST ANCHORAGE AK 99508 TRADING BAY ENERGY CORP PAUL CRAIG 5432 NORTHERN LIGHTS BLVD ANCHORAGE AK 99508 US MIN MGMT SERV AK OCS REGIONAL DIR 949 E 36TH AV RM 110 ANCHORAGE AK 99508-4302 e REGIONAL SUPRVISOR, FIELD OPERATNS MINERALS MANAGEMENT SERVICE ALASKA OCS REGION 949 E 36TH AV STE 308 ANCHORAGE AK 99508-4363 US MIN MGMT SERV LIBRARY 949 E 36TH AV RM 603 ANCHORAGE AK 99508-4363 US MIN MGMT SERV FRANK MILLER 949 E 36TH AV STE 603 ANCHORAGE AK 99508-4363 USGS - ALASKA SECTION LIBRARY 4200 UNIVERSITY DR ANCHORAGE AK 99508-4667 GAFO GREENPEACE PAMELA MILLER POBOX 104432 ANCHORAGE AK 99510 BRISTOL ENVIR SERVICES JIM MUNTER POBOX 100320 ANCHORAGE AK 99510-0320 e e 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 ANCHORAGE TIMES BERT TARRANT POBOX 100040 ANCHORAGE AK 99510-0040 ARCO ALASKA INC JENNY KEARNEY ATO 1255 POBOX 100360 ANCHORAGE AK 99510-0360 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 e e 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 ARCO ALASKA INC KUP CENTRAL WELLS ST TSTNG WELL ENG TECH NSK 69 POBOX 196105 ANCHORAGE AK 99510-6105 ALYESKA PIPELINE ROSS C. OLIVER, TAPS PLANNER 1835 S BRAGAW ST ANCHORAGE AK 99512 ALYESKA PIPELINE SERV CO CHUCK O'DONNELL 1835 S BRAGAW - MS 530B ANCHORAGE AK 99512 US BUREAU OF LAND MGMT OIL & GAS OPRNS (984) J A DYGAS 222 W 7TH AV #13 ANCHORAGE AK 99513-7599 JWL ENGINEERING JEFF LIPSCOMB 9921 MAIN TREE DR. ANCHORAGE AK 99516-6510 GERALD GANOPOLE CONSULT GEOL 2536 ARLINGTON ANCHORAGE AK 99517-1303 e e ALYESKA PIPELINE SERV CO PERRY A MARKLEY 1835 S BRAGAW - MS 575 ANCHORAGE AK 99512 ALYESKA PIPELINE SERV CO LEGAL DEPT 1835 S BRAGAW ANCHORAGE AK 99512-0099 ANCHORAGE DAILY NEWS EDITORIAL PG EDTR MICHAEL CAREY POBOX 149001 ANCHORAGE AK 99514 NORTHERN CONSULTING GROUP ROBERT BRITCH, P.E. 2454 TELEQUANA DR. ANCHORAGE AK 99517 DAVID CUSATO 600 W 76TH AV #508 ANCHORAGE AK 99518 ASRC CONRAD BAGNE 301 ARCTIC SLOPE AV STE 300 ANCHORAGE AK 99518 ARMAND SPIELMAN 651 HILANDER CIRCLE ANCHORAGE AX 99518 OPSTAD & ASSOC ERIK A OPSTAD PROF GEOL POBOX 190754 ANCHORAGE AK 99519 ENS TAR 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 e 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 AX 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 · . ~i~iŒ (ffi~ ~~~~[\~ e AI4ASHA OIL AND GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 443.01 Mr. Chip Alvord Alpine Drilling Team Leader ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Spacing Exception for Colville River Unit CD 1-46 Well Dear Mr. Alvord: On June 1, 2004, the Alaska Oil and Gas Conservation Commission ("Commission") received correspondence from ConocoPhillips Alaska, Inc. ("CP AI") dated May 28, 2004 requesting a waiver of spacing requirements for drilling and operation of the Colville River Unit ("CRU") CD 1-46 service well. On July 1, 2004, the Commission received a revised request for exception from CP AI dated June 29, 2004. This well will lie entirely within state leases ADL 025559, ADL 372095 and ADL 372096, and more than 500 feet from any property lines where ownership changes. The productive interval ofCRU CDI-46 will lie within the Alpine Oil Pool, and will approach within approximately 421 feet of existing well CRU CDI-37, which is also open to the Alpine Oil Pool. Conservation Order 443 ("CO 443") governs the Alpine Oil Pool within the Colville River Unit. An exception to the spacing requirements of Rule 3 is required, as CRU CDI-46 will open the pool within 500 lineal feet of existing well CRU CDI-37. Rule 10 of CO 443 states: "Upon proper application or its own motion, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, or compromise ultimate recovery and is based on sound engineering principles." Administrative approval is appropriate for a waiver of well spacing requirements specified in CO 443. Notice and public hearing are not required for this spacing exception application as CRU CDI-46 will be located entirely within unitized State leases ADL 25559, ADL 372095 and ADL 372096, and within the Alpine Participating Area ("P A"). The well will lie more than 500 feet from the boundary of the Colville River Unit and the boundary of the Alpine P A. Correlative rights will not be jeopardized. e AA443.01 July 13, 2004 Page 2 of2 . The Commission has determined drilling and operation of the CRU CDl-46 well will not promote waste, will not jeopardize correlative rights, will enhance ultimate recovery, will not result in an increased risk of fluid movement into freshwater, and is based on sound engineering and geoscience principles. The Commission hereby approves the drilling and operation of the Colville River Unit CDI-46 well as proposed. ervation Commission ø~ Commissioner cc: Ms. Dora 1. Soria, ConocoPhillips Alaska, Inc. Citgo Petroleum Corporation PO Box 3758 Tulsa, OK 74136 Kelly Valadez Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Kay Munger Munger Oil Information Service, Inc PO Box 45738 Los Angeles, CA 90045-0738 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 e . Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Robert Gravely 7681 South Kit Carson Drive Littleton, CO 80122 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 John Levorsen 200 North 3rd Street, #1202 Boise, ID 83702 Samuel Van Vactor Economic Insight Inc. 3004 SW First Ave. Portland, OR 97201 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 3940 Arctic Blvd., Ste 300 Anchorage, AK 99503 David Cusato 200 West 34th PMB 411 Anchorage, AK 99503 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 North Slope Borough PO Box 69 Barrow, AK 99723 t/w Ø~¡ CHECKLlI- SPACING EXCEPTION A.LlCATION OPERATOR ConocoPhillips PROPERTY ID/ LEASE S: ADL 25559 FIELD/POOL Covlille Riv. Field, Alpine Oil Pool WELL NAME CRU CD1-46 PI/SH: ADL 25559 VERTICAL EXPLORATORY GAS DEVIATED x DELINEATION OIL x DEVELOPMENT x SURFACE LOCATION PRODUCTIVE INTERVALS (Top and Bottom) BOTTOM HOLE 544' FNL and 3,022' FEL, S. 05, T11 N, R 05 W, UM 3,238' FNL and 764' FEL, S. 08, T11 N, R 05 W, UM 2,060' FNL and 1,403' FEL, S. 16, T11 N, R 05 W, UM 2,060' FNL and 1,403' FEL, S. 16, T11 N, R 05 W, UM Check applicable reason(s) for spacing exception per 20 AAC 25.055(a): (1) to drill a well for oil within 500 feet of a property line where ownership or landownership chan es, (2) to drill a well for gas within 1500 feet of a property line where ownership or landownership chan es, (3) to drill and complete more than one oil well in a governmental quarter section; or x to drill and complete an oil well closer than 500' to any well drilling to or capable of producin from the same pool, 4) to drill and com lete more than one as well in a overnmental section; or or to drill and complete a gas well closer than 3000' to any well drilling to or ca able of roducin from the same 001. Does the application contain: A brief explanation for wh the operator has chosen to drill the specified location. A plat drawn to a scale of one inch equaling 2,640 feet or larger, showing the x location of the well or portion of the well for which the exception is sought, all other completed and drilling wells on the property, and all adjoining properties and wells within 1,000 feet of a well or portion of the well requiring the spacing exception that is drilling for oil or within 3,000 feet of a well or portion of the well requiring the s acin exce tion that is drillin for as. The names of all owners, landowners, and operators of all properties within 1,000 x feet of a well or portion of the well requiring the spacing exception that is drilling for oil or within 3,000 feet of a well or portion of the well requiring the spacing exception that is drillin for as. A copy of the notice sent by certified mail to the owners, landowners and operators x described above, the date of mailing, and the addresses to which the notice was sent. x An affidavit by a person acquainted with the facts verifying that all facts are true and that the plat correctl portra s pertinent and re uired data. If the operator requests a variance from the notice requirements of 20AAC25.055(d), sufficient information to demonstrate that it is not feasible to comply with the notice requirements because of the complexity of ownership within the notice area. 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 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 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 9961l PHILLIPS PETR ALASKA OPERATIONS MANAGER J W KONST P 0 DRAWER 66 KENAI AK 9961l KENAI PENINSULA BOROUGH ECONOMIC DEVEL DISTR STAN STEADMAN POBOX 3029 KENAI AK 99611-3029 BELOWICH COAL CONSULTING MICHAEL A BELOWICH HC31 BOX 5157 WASILLA AK 99654 PACE SHEILA DICKSON POBOX 2018 SOLDOTNA AK 99669 ALYESKA PIPELINE SERVICE CO VALDEZ CORP AFFAIRS SANDY MCCLINTOCK POBOX 300 MS/701 VALDEZ AK 99686 VALDEZ VANGUARD EDITOR POBOX 98 VALDEZ AK 99686-0098 e . PENNY VADLA POBOX 467 NINILCHIK AK 99639 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 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 HAKKILA POBOX 61604 FAIRBANKS AX 99706-1604 FAIRBANKS DAILY NEWS-MINER KATE RIPLEY POBOX 70710 FAIRBANKS AK 99707 DEPT OF NATURAL RESOURCES DIV OF LAND REG MGR NORTHERN REGION 3700 AIRPORT WAY FAIRBANKS AX 99709-4699 ASRC BILL THOMAS POBOX 129 BARROW AK 99723 e e RICK WAGNER POBOX 60868 FAIRBANKS AK 99706 C BURGLIN POBOX 131 FAIRBANKS AK 99707 FRED PRATT POBOX 72981 FAIRBANKS AX 99707-2981 K&K RECYCL INC POBOX 58055 FAIRBANKS AK 99711 RICHARD FINEBERG POBOX 416 ESTER AX 99725 . 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 DEFE 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 X13 Page 1 of 2 Maunder, Thomas E (DOA) From: NSK Well Integrity Proj [N1878 @conocophillips.com] Sent: Tuesday, November 24, 2009 1 :02 PM To: Maunder, Thomas E (DOA) Subject: RE: Alpine SSSV Clarification Thanks! MJ From: Maunder, Thomas E (DOA) [mailto:tom.maunder @alaska.gov] Sent: Tuesday, November 24, 2009 10 :22 AM To: NSK Well Integrity Proj Cc: Regg, James B (DOA); Schwartz, Guy L (DOA) Subject: RE: Alpine SSSV Clarification MJ, It is not necessary to keep a SSSV in a well that is SI. When a SI well is returned to service, the standard SSV /SSSV test must be accomplished within 2 weeks as usual. As stated in your note of November 17, plan to send us a note regarding the status of the well and the SSSV. Call or message with any questions. Tom Maunder, PE AOGCC From: Maunder, Thomas E (DOA) Sent: Tuesday, November 17, 2009 3:50 PM To: 'NSK Well Integrity Proj' Subject: RE: Alpine SSSV Clarification Must be hoping to live in the same world. I think those new /proposed SVS regs even say that a SSSV is not needed if the well is SI. From: NSK Well Integrity Proj mailto :N1878 @conocophillips.com] Sent: Tuesday, November 17, 2009 3:26 PM To: Maunder, Thomas E (DOA) Subject: RE: Alpine SSSV Clarification Nope, never... In my perfect future world we would just send you a note for your file that says it is SI long term and we have the SSSV pulled.... I'll check back next week mj From: Maunder, Thomas E (DOA) [maiito:tom.maunder @alaska.gov] Sent: Tuesday, November 17, 2009 2:51 PM To: NSK Well Integrity Proj Subject: RE: Alpine SSSV Clarification 11/24/2009 Page 2 of 2 MJ, I will have to check with Jim when he gets back next week, but I don't think CPAI's interpretation is correct. You state that it has been CPAI's practice to request approval to leave the SSSV out on LT SI wells. Have we denied that? Tom From: NSK Well Integrity Proj mailto :N1878 @conocophillips.com] Sent: Tuesday, November 17, 2009 8:07 AM To: Maunder, Thomas E (DOA) Subject: Alpine SSSV Clarification Tom, 1 have a SSSV clarification question for Alpine wells. CO 443 Rule 5 says: (a.) All production wells must be equipped with a fail -safe automatic surface safety valve (SSV) and a surface controlled subsurface safety valve (SSSV). (b.) Injection wells must be equipped with a double check valve arrangement. CPAI has interpreted this as the wells will have SSSV's installed even if the wells are shut in and have historically requested AOGCC approval to leave SSSV's out of long term SI welts for monitoring purposes. My clarification question is: have we interpreted the regulation correctly? Do we need Commission approval to leave a SSSV out of a long tern SI well? Please advise. MJ Loveland Well Integrity Project Supervisor ConocoPhiltips Alaska, Inc. Office (907) 659 -7043 Cell (907) 943 -1687 11/24/2009 #12 {. e e ~ ConocoPhillips Alaska, Inc. JUl 0 ?004 P. O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Dora I. Soria Land Department, A TO 1466 Telephone 907- 265-6297 Facsimile 907- 263-4966 E-mail dora.i.soria@conocophillips.com June 29, 2004 VIA CERTIFIED MAIL RETURN RECEIPT REQUESTED Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 W. ih Avenue, Suite 100 Anchorage, Alaska 99501 Re: Revised request for Exception to 20 AAC 25.055 Alpine CD1-37 and CD1-46 Alpine Field, Colville River Unit North Slope, Alaska AR-101941 Dear Chairman Norman: ConocoPhillips Alaska, Inc. ("CPAI"), for itself and on behalf of the co-owners of the Alpine Field, hereby applies for an administrative exception to the provisions of 20 AAC 25.055 for the drilling of the CD1-37 and the CD1-46 Wells (the "Wells"). The CD1-37 Well was drilled as a directional hole from a surface location of 479' FNL and 2959' FEL of Section 5, T11 N-R5E, UM to a bottomhole location of 2828' FNL and 924' FNL, Section 8, T11 N-R5E, UM; and the CD1-46 Well was drilled as a directional hole from a surface location of 544' FNL and 3022' FEL of Section 5, T11 N-R5E, UM to the 7" casing point of 3238' FNL and 764' FEL, Section 8, T11 N- R5E, UM. The surface and bottomhole locations of the Wells are on ADL-25559, which lease is owned by CPAI and Anadarko Petroleum Corporation. It was planned to have approximately 540 feet of separation between the toe of CD1-37 and the beginning of the open-hole section of CD1-46, at the 7" casing point. Upon reprocessing the surveys for the Wells, it was discovered that the separation between the open-hole sections of the Wells was approximately 421 feet. '." . e e .. The Exhibit 1 showing the location of the Wells, all other adjoining governmental quarter sections, and all other completed and drilling wells remains the same. The names and addresses of all owners and operators of the governmental quarter sections directly and diagonally offsetting the Wells set forth in the Exhibit 2 also remain the same. Included in the attached Exhibit 3 is the verification required by the referenced provisions, a copy of the notice sent to the other owners listed in Exhibit 2, and the date such notice was mailed. If you have any questions or require any additional information regarding this application, please contact Vern Johnson at 265-6081 or me at 265-6297. Very truly yours, -~.L'. ~ Dora I. Soria Senior Landman DIS (war) Attachments '. Conoc~hillips Well ~~~~16ci1 Surface l.ocation: 479' FNl., 2959' Sec. T11 N, R5E, UM Bottom Hole l.ocation: 2828' FNl., 924' Sec. 8, T11 N, R5E, UM Well Name: CD1 -46 Surface l.ocation: 544' FNl., 3022' Sec. T11 N, R5E, UM Bottom Hole l.ocation: 3238' FNl., 764' Sec. 8, T11 N, R5E, UM Scale: 112 Mile 5-26-04 04052601000 e e EXHIBIT 2 List of all owners and operators of governmental quarter sections directly and diagonally offsetting the quarter section of the CD1-46 and CD1-37 Wells, both having a bottom hole location on the NE4 of Sec. 8, T11 N-R5E, UM. Operator: ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99501-0360 Non-Operator(s): Anadarko Petroleum Corporation 1201 Lake Robbins Dr. The Woodlands, TX 77252-1330 Attn: Mr. Mike Nixson Phillips Alpine Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Attn: Mr. James M. Ruud Royalty Owner(s): State of Alaska Department of Natural Resources Division of Oil and Gas 3601 C Street, Suite 1380 Anchorage, AK 99503-5948 Attn: Mr. Mark Myers, Director Arctic Slope Regional Corporation 1230 Agvik Street Barrow, Alaska 99723 Attn: Vice Presidents, Lands Overriding Royalty Owner(s): ConocoPhillips Alaska, Inc. Mr. James M. Ruud P. O. Box 100360 Anchorage, Alaska 99510-0360 (907) 263-4933 Fax: (907) 263-4966 Petro-Hunt, L.L.C. Mr. Joe Lucas 1601 Elm Street, Suite 3500 Dallas, Texas 75201 (214) 880-8400 Fax: (214) 880-7101 Chevron U. S. A. Inc. Mr. Todd Kratz P. O. Box 36366 Houston, Texas 77236 (281) 561-3653 Fax: (281) 561-3880 Hunt Petroleum Corporation Mr. Steve Brooks 3400 Thanksgiving Tower Dallas, Texas 75201 (214) 880-8920 Fax: (214) 880-8951 Rosewood Resources Mr. Hiram Lucius 2711 No. Haskell, Suite 2800 LB #22 Dallas, Texas 75204 (214) 756-6600 Fax: (214) 756-6666 · e e EXHIBIT 3 TO THE ALASKA OIL AND GAS CONSERVATION COMMISSION Before the Commissioners of the ) Alaska Oil and Gas ConseNation ) VERIFICATION OF FACTS AND Commission in the Matter of the ) AFFIDAVIT OF DORA I. Request of ConocoPhillips Alaska, Inc.) SORIA For an Exception to the Provisions ) of 20 AAC 25.055 for Conoco- ) Phillips Alpine CD1-37 and CD1-46 ) ) STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT ) Dora I. Soria, being first duly sworn, upon oath, deposes and states as follows: 1 . My name is Dora I. Soria. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. I am a Senior Landman for the well operator, ConocoPhillips Alaska, Inc. 3. I am acquainted with the facts associated with the drilling of Alpine CD1-37 and CD1-46 4. I have reviewed the application submitted for the exception to 20 AAC 25.055. To the best of my knowledge and belief all facts therein are true and accurate. 5. I have reviewed the plat attached as Exhibit 1 and it correctly portrays pertinent and required data. 6. Pursuant to 20 AAC 25.055 (b)"ConocoPhillips Alaska, Inc. ("CPAI"), the well operator, prepared a Notice of Request for Exception to the Provision of 20 AAC 25.055. A copy of this notice is attached hereto. · . ~ '4 e e 7. On June 29, 2004 pursuant to 20 AAC 25.055 (b), CPAI sent a copy of said notice by certified mail to the last known address of all owners and operators of governmental quarter sections directly and diagonally offsetting the governmental quarter section of the proposed location of CPAl's Alpine CD1-37 and CD1-46. These names and addresses are set forth on Exhibit 2 attached to CPAl's Request for Exception to Provisions of 20 AAC 25.055 dated June 29,2004. Subscribed and sworn to this 29th day of June, 2004. Æ · · - ~ ,/. /J~/L( tfL. Dora I. Soria STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT ) This instrument was acknowledged before me this 29th day of June, 2004, by Dora I. Soria. OFFICIAL SEAL State of Alaska NOTARY PUBLIC KAY H. LA BAU My Comm. Expire.: June a, 2007 N!~u~ic.~'::ÄlaSka My Commission ExPires:~ ~ tP..Þ07 #11 e . ~ ConocoPhillips Alaska, Inc. P. O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 RECEIVE ,JUN 012004 Alaska Oil & ~''''h Commission ¡. í1;", Drage . Dora I. Soria Land Department, A TO 1466 Telephone 907· 265-6297 Facsimile 907- 263-4966 E-mail dora.i.soria@conocophillips.com May 28, 2004 VIA CERTIFIED MAIL RETURN RECEIPT REQUESTED Mr. John Norman, Chairman Alaska Oil and Gas Conservation Commission 333 W. ¡th Avenue, Suite 100 Anchorage, Alaska 99501 . Re: Request for Exception to 20 AAC 25.055 Alpine CD1-37 and CD1-46 Alpine Field, Colville River Unit North Slope, Alaska AR-101941 Dear Chairman Norman: ConocoPhillips Alaska, Inc. ("CPAI"), for itself and on behalf of the co-owners of the Alpine Field, hereby applies for an administrative exception to the provisions of 20 AAC 25.055 for the drilling of the CD1-37 and the CD1-46 Wells (the "Wells"). The CD1-37 Well was drilled as a directional hole from a surface location of 479' FNL and 2959' FEL of Section 5, T11 N-R5E, UM to a bottomhole location of 2828' FNL and 924' FNL, Section 8, T11 N-R5E, UM; and the CD1-46 Well was drilled as a directional hole from a surface location of 544' FNL and 3022' FEL of Section 5, T11 N-R5E, UM to a bottom hole location of 3238' FNL and 764' FEL, Section 8, T11 N-R5E, UM. The surface and bottom hole locations of the Wells are on ADL- 25559, which lease is owned by CPAI and Anadarko Petroleum Corporation. It was planned to have approximately 540 feet of separation between the bottomholes of the CD1-37n and CD1-46. Upon reprocessing the surveys for the Wells, it was discovered that the separation between the Wells was more like 420.5 feet The attached Exhibit 1 shows the location of the Wells, all other adjoining governmental quarter sections, and all other completed and drilling wells. The names and addresses of all owners and operators of the governmental quarter sections directly and diagonally offsetting the Wells are set forth in the attached e e Exhibit 2. Included in the attached Exhibit 3 is the verification required by the referenced provisions, a copy of the notice sent to the other owners listed in Exhibit 2, and the date such notice was mailed. If you have any questions or require any additional information regarding this application, please contact Vern Johnson at 265-6081 or me at 265-6297. Very truly yours, -CÚÆa-,('.~ Dora I. Soria Senior Landman DIS (war) Attachments IT 1 ~. ConocoPhillips Surface location: Bottom Hole location: 2828' FNl, 924' Well Name: CD1..46 Surface location: 544' Bottom Hole location: 3238' ÎI2 Mile T11 N, Sec. 8, T11N, e e EXHIBIT 2 List of all owners and operators of governmental quarter sections directly and diagonally offsetting the quarter section of the CD1-46 and CD1-37 Wells, both having a bottomhole location on the NE4 of Sec. 8, T11 N-R5E, UM. Operator: ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99501-0360 Non-Operator(s): Anadarko Petroleum Corporation 1201 Lake Robbins Dr. The Woodlands, TX 77252-1330 Attn: Mr. Mike Nixson Phillips Alpine Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Attn: Mr. James M. Ruud Royalty Owner(s): State of Alaska Department of Natural Resources Division of Oil and Gas 3601 C Street, Suite 1380 Anchorage, AK 99503-5948 Attn: Mr. Mark Myers, Director Arctic Slope Regional Corporation 1230 Agvik Street Barrow, Alaska 99723 Attn: Vice Presidents, Lands Overriding Royalty Owner(s): ConocoPhillips Alaska, Inc. Mr. James M. Ruud P. O. Box 100360 Anchorage, Alaska 99510-0360 (907) 263-4933 Fax: (907) 263-4966 Hunt Petroleum Corporation Mr. Steve Brooks 3400 Thanksgiving Tower Dallas, Texas 75201 (214) 880-8920 Fax: (214) 880-8951 Petro-Hunt, L.L.C. Mr. Joe Lucas 1601 Elm Street, Suite 3500 Dallas, Texas 75201 (214) 880-8400 Fax: (214) 880-7101 Rosewood Resources Mr. Chris Kidd 200 Crescent Court, Suite 300 Dallas, Texas 75201 (214) 871-5700 Fax: (214) 871-5110 Chevron U. S. A. Inc. Mr. Todd Kratz P. O. Box 36366 Houston, Texas 77236 (281) 561-3653 Fax: (281) 561-3880 e e EXHIBIT 3 TO THE ALASKA OIL AND GAS CONSERVATION COMMISSION Before the Commissioners of the ) Alaska Oil and Gas Conservation ) VERIFICATION OF FACTS AND Commission in the Matter of the ) AFFIDAVIT OF DORA I. Request of ConocoPhillips Alaska, Inc.) SORIA For an Exception to the Provisions ) of 20 AAC 25.055 for Conoco- ) Phillips Alpine CD1-37 and CD1-46 ) ) STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT ) Dora I. Soria, being first duly sworn, upon oath, deposes and states as follows: 1 . My name is Dora I. Soria. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. I am a Senior Landman for the well operator, ConocoPhillips Alaska, Inc. 3. I am acquainted with the facts associated with the drilling of Alpine CD1-37 and CD1-46 4. I have reviewed the application submitted for the exception to 20 AAC 25.055. To the best of my knowledge and belief all facts therein are true and accurate. 5. I have reviewed the plat attached as Exhibit 1 and it correctly portrays pertinent and required data. 6. Pursuant to 20 AAC 25.055 (b), ConocoPhillips Alaska, Inc. ("CPAI"), the well operator, prepared a Notice of Request for Exception to the Provision of 20 AAC 25.055. A copy of this notice is attached hereto. e e 7. On May 28, 2004 pursuant to 20 AAC 25.055 (b), CPAI sent a copy of said notice by certified mail to the last known address of all owners and operators of governmental quarter sections directly and diagonally offsetting the governmental quarter section of the proposed location of CPAl's Alpine CD1-37 and CD1-46. These names and addresses are set forth on Exhibit 2 attached to CPAl's Request for Exception to Provisions of 20 AAC 25.055 dated May 28, 2004. Subscribed and sworn to this 28th day of May, 2004. -d44a. J. ~ Dora I. Soria STATE OF ALASKA ) ) §§ THIRD JUDICIAL DISTRICT ) This instrument was acknowledged before me this 28th day of ~, 2004, by Dora I. Soria. OFFICIAL SEAL State of Alaska NOTARY PUBLIC GEORGIA C. MONZON My Comm. Expires: May 7, 2007 ~e.'m~ Notary Public, State of laska My Commission Expires: MAY 0 7 2007 e e Conoc~hillips Alaska, Inc. P. O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 Dora I. Soria Land Department, A TO 1466 Telephone 907- 265-6297 Facsimile 907- 263-4966 E-mail dora.i.soria@conocophillips.com May 28, 2004 VIA CERTIFIED MAIL RETURN RECEIPT REQUESTED Alpine PA Owners - Tracts 4, 45, 61, and 62 (See Attached List) Re: Notice of Request for Exception to 20 AAC 25.055 Alpine CD1-37 and CD1-46 Alpine Field, Colville River Unit North Slope, Alaska AR-101941 Ladies and Gentlemen: Pursuant to the provisions of 20 AAC 25.055(b), ConocoPhillips Alaska, Inc. ("·CPAI") hereby gives notice of a request to the Alaska Oil and Gas Conservation Commission for an exception to the spacing requirement provisions of 20 AAC 25.055 for the drilling of the CD1-37 and the CD1-46 Wells (the "Wells") in the Alpine Field. The CD1-37 Well was drilled as a directional hole from a surface location of 479' FNL and 2959' FEL of Section 5, T11 N-R5E, UM to a bottom hole location of 2828' FNL and 924' FNL, Section 8, T11 N-R5E, UM; and the CD1-46 Well was drilled as a directional hole from a surface location of 544' FNL and 3022' FEL of Section 5, T11 N-R5E, UM to a bottom hole location of 3238' FNL and 764' FEL, Section 8, T11 N-R5E, UM. The surface and bottom hole locations of the Wells are on ADL-25559, which lease is owned by CPAI and Anadarko Petroleum Corporation. It was planned to have approximately 540 feet of separation between the bottom holes of the CD1-37 and CD1-46. Upon reprocessing the surveys for the Wells, it was discovered that the separation between the Wells was approximately 420.5 feet. e e A plat showing the location of the Wells, leasehold ownership and all other completed and drilling wells in the area is attached as Exhibit 1. If you have any questions or require any additional information regarding this application, please contact Vern Johnson at 265-6081 or me at 265-6297. Very truly yours, . - t:ÍJA.Lt ~'. ~ Dora I. Soria Senior Landman DIS (war) Attachments e e Alpine PA Owners - Tracts 4,45,61, and 62 State of Alaska Department of Natural Resources Division of Oil and Gas 3601 C Street, Suite 1380 Anchorage, AK 99503-5948 Attn: Mr. Mark Myers, Director Hunt Petroleum Corporation Mr. Steve Brooks 3400 Thanksgiving Tower Dallas, Texas 75201 (214) 880-8920 Fax: (214) 880-8951 Arctic Slope Regional Corporation 1230 Agvik Street Barrow, Alaska 99723 Attn: Vice Presidents, Lands Chevron U. S. A. Inc. Mr. Todd Kratz P. O. Box 36366 Houston , Texas 77236 (281) 561-3653 Fax: (281) 561-3880 Phillips Alpine Alaska, Inc. Mr. James M. Ruud P. O. Box 100360 Anchorage, Alaska 99510-0360 (907) 263-4933 Fax: (907) 263-4966 Anadarko Petroleum Corporation 1201 Lake Robbins Dr. The Woodlands, TX 77252-1330 Attn: Mr. Mike Nixson Petro-Hunt, L.L.C. Mr. Joe Lucas 1601 Elm Street, Suite 3500 Dallas, Texas 75201 (214) 880-8400 Fax: (214) 880-7101 Rosewood Resources Mr. Chris Kidd 200 Crescent Court, Suite 300 Dallas, Texas 75201 (214) 871-5700 Fax: (214) 871-5110 CC: Arctic Slope Regional Corporation 3900 C Street, Suite 801 Anchorage, AK 99503-5963 Attn: Ms. Teresa Imm Resource Development Manager EXHIBIT 1 conocóPhillips Well Name: CD1-37 Surface Location: 479' FNL, 2959' FEL, Sec. 5, T11N, RSE, UM Bottom Hole Location: 2828' FNL, 924' FEL, Sec. 8, T11 N, R5E, UM Well Name: CD1-46 Surface Location: 544' FNL, 3022' FEL, Sec. S, T11 N, R5E, UM Bottom Hole Location: 3238' FNL, 764' FEL, Sec. 8, T11 N, RSE, UM Scale: 1-'2 Mile 5-26-04 04052601 COO #10 . . 1 (r~\ ¡ ! II I ~ \ . , \ i)} \ '-, .' -'" FRANK H. MURKOWSKI, GOVERNOR AI.ASIiA OIL AND GAS CONSERVADONCO~SSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 February 12, 2004 Michael D. Erwin Alpine Production Engineer ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Dear Mr. Erwin: By letter dated February 10,2004 ConocoPhillips Alaska, Inc. ("CPA") requested a tem- porary waiver of Conservation Order No. 443, Rule 9a, which requires two well tests per month for all Colville River Field, Alpine Oil Pool wells. You anticipate a time period of two weeks to four weeks, in April to May, 2004 during which time you will replace a CD- 2 test separator necessary for some Alpine well testing. Alaska Oil and Gas Conservation Commission hereby waives Alpine Oil Pool well test requirements e ested, during the above specified time period. Sincerely, (}j fJjÞ¡ Daniel T. Seamount, Jr. Commissioner . I . . ( . -~ ConocoPhillips Alaska, Inc. Michael D. Erwin Alpine Production Engineer ConocoPhillips Alaska 700 G Street Anchorage, AK 99501 Phone: (907) 265-1478 February 10, 2004 Attention: Commissioners Daniel Seamount and John Norman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: CD2 Test Separator Replacement Alpine Oil Pool/Colville River Field Dear Commissioners: In response to discussions with your staff, ConocoPhillips Alaska, Inc., as an owner and the operator of the Colville River Unit, request temporary waiver of Rule 9a, Conservation Order #443 for the Colville River Unit and Alpine Oil Pool. Rule 9a requires two well tests per month for all Alpine Oil Pool wells. The reason for the waiver regards the pending replacement of our test facility at CD-2. We are installing a new test separator this winter to replace the current test vessel. The new vessel is better suited for the higher than expected rates from our CD-2 wells. Installation is slated between late April and early May, and could impact testing for 2-4 weeks. During the construction and start-up period there may from time to time be intervals where the test separator is unavailable for service thereby impacting our ability to meet the obligations of Rule 9a without shutting in wells. Inquiries regarding this report may be directed to Mike Erwin or myself at this office. Sincerely, /~^~ ~ Michael D. Erwin Alpine Production Engineer RECEIVED FEB 1 2 2004 Alaska Oil & Gas Cons, Commission Anchorage i ~ . . ., cc: Mr. Kenneth A. Boyd, Director Alaska Department of Natural Resources Division of Oil & Gas 550 W. 7th Avenue Suite 800 Anchorage, Alaska 99501-3560 Ms. Teresa Imm, 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 Mrs. Catherine Lively Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 Todd Liebel Anadarko Petroleum Corporation PO Box 1330 Houston, Texas 77251-1330 #9 '$~&~[ It ~~~$~~ DEPARTMENT OF NATURAL RESOURCES TONY KNOWLES. GOVERNOR DIVISION OF OIL AND GAS 3601 "C" STREET, SUI1E 1380 ANCHORAGE, ALASKA 99503-5948 PHONE: (907) 269-8800 December 16, 1998 Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Via Fax (276-7542) and Mail Attn: David W. Johnston Commissioner Subject: Colville River Field, Alpine Pool Rules ORIGINAL Dear Commissioner Johnston: The Department of Natural Resources, Division of Oil and Gas ("DNR") reviewed the proposed rules for the Colville River Field, Alpine Oil Pool and provides the following comments regarding the proposed Rule 8. Production Practices for the Alpine Oil Pool. ARCO requested one well test per month for the first year of production and quarterly well testing thereafter. This frequency of testing may be appropriate later in the pool's life. It is premature now. Based on the information available to the DNR and the development plans provided in ARCO's testimony to the Commission, the number of production wells per pad should not overwhelm the Alpine testing facilities for some time. Early in the Alpine Field life, a testing frequency that maximizes the use of the available testing facilities should be the rule, not the exception. The rule could be amended later to address the situation of a high concentration of production wells per pad per test facilities. ARCO correctly states that the production, and hence royalty revenue, allocated to each tract within an Alpine Participating Area (AP A) will be based on_ a reservoir model simulation. Test data will be one of the most important inputs to the reservoir simulator that allocates the reserves by tract. "Develop, Conserve and Enhance Natural Resources for Present and Future Alaskans VI .@ :print~d on fecycled paper b y " . . .. David W. Johnston December 16, 1998 Page 2 More frequent well testing than outlined in ARCa's proposal is needed to ensure that the well tests accurately represent oil, gas and water production rates and the historic production volumes from the various tracts/leases that will comprise the Alpine ail Pool and the AP A. Accurate production data will be necessary to calibrate the reservoir model. Finally, the Colville River Unit has two royalty owners, the State of Alaska and the Arctic Slope Regional Corporation. Because of the importance of the reservoir simulator to the tract allocation process, the royalty owners in their approval of an AP A will likely require more frequent well testing than that proposed by ARca. To be consistent with other North Slope participating areas where individual well testing is an important aspect of the production allocation process, two well tests per month per well may be the minimum initial testing frequency acceptable to the DNR for the AP A. Sincerely, ~h Kenneth A. Boyd Director C-., ~ cc: Mark Ireland - ARCa Teresa Imm - ASRCC Jack Hartz - AOGCC AOGCC.alpine CO.doc State of Alaska Dcputmcnt of Natural Resource Division of Oil & Gas . 3601 C Street, Suite 138Q . Anchorage. AK 99503-5948 (907) 269-8784 DIRECTORS OFFICE . FAX NO. 5623582 . P. 01 DEC-16-98 WED 04:11 PM ~~~©~~ ....---.....,___-..~.. .....-.... ..~,~......-----.....'.,~ .............----~"" TO: ~.I2ø.uld..._...:\okK4:Q~. ~COMþANyL ","0 ~C ~ ,~. ..FROM:..._.,_...... __~ "". ~.~~L-.."., PHONE: ,....0....-- ..-......._____ ..._ FAX NO.: ,;) 76 - 7S((.;t -".".._..-_--"-"_.-~--.....~- PHONE: (907) ,....____"""......______.'....·'..'Ift ...'.I.'.___-~". G··,···..·-I~·---·····-· . .~., DATE: ,~- If., -~B --_..-..."...._---_......,...'...._._-..,~..,.._-"......,...-..- -T~AX N~:.:.¡~º.?1562-38?,~.__..~..J .._J!~~~~J'"~_..l!: ~q!~___..._._____... [C: ~~-=~._=_~~~-=_~ ~~ ] 3 Number of pages including cover sheet: o Urgent o For Review o Please Comment o As You Requested DFYr ~~.~~1!.9_'!..:.-_...,,'_____''',....__.~,..~__....___..,..__..___.....____...., ,.,._._...__.._~"'"__~..".._____ ..-..,...-..--------...,.....-.........-..--"...---- ",. 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"__"_""" ... ...,t.___......" ,.._._._"__..__....,·,'''_____........"'.___..-,'''_.-_a~~.''''.__._. ...__--...,~__...,..'II!I..__.~,,______ ,...__......,,,.._--."w.._._.___...., .__.. ---....,.._.._-------.-.,~....__.._,-_.._-......_--"_..._."'...-.....---"."~' ..~--.""..._--_..."..._--.......,',.._.."'------_.~."...- .~., ".-.----.",...,..---.--...-.,.......-.----... -, ...-----"'-----. '''~_....---. .--- ... ----".--.--...,' .___._. ~""..____....._ ..""......_ - I --.,.-.",... ----.--..." ,,-_. ---'--'---'-.".~"""" ___w, .-._-....~,....... ...... .-----,,,___,.,,,___.___ .......--~.,...___..r".___...,~.,____.......,_'_____.....__. .__po ..,.......___._. "..__.___"." ""~...n.____._.."~..___.._.__,_......~_._.....)~_...._..,,.., .__..___"" "_.__...'._ _.,. .".._._.__.." .____"......____.___....."..._. S:\tandg\rol ms\Fnfonn.dQc 7(] 3198 ORtG\NAL #8 "' ARca Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . ~~ ~". December 16, 1998 Mr. D.W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Alpine Pool Rules Dear Chairman Johnston: In response to your conversation with Mike Erwin yesterday, this letter is to confirm that production rate plots for the "proposed development plan" as described during the December 3, 1998, Alpine Pool Rule Hearing before the Commission, will be presented to the AOGCC in the coming months. At the present time, ARCO Alaska, Inc has not finalized its production rate projections for the "proposed" development plan and is developing the technical justification supporting this proposal. This will require additional data gathering and revision of our full field reservoir model. Upon completion of the studies to optimize the recovery process - waterflood only, miscible flood, WAG, or some combination - and financial authorization by all parties, we will return to the Commission requesting an Area Injection Order. At that time, currently projected for the summer of 1999, we will present a final development plan and associated production forecast. For additional information or supporting documentation, please contact Mike Erwin at 265-1478. Sincerely, Mark Ireland þt~ OR/GINA\L F~ ot '" . . -... .' 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 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- 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 File #7 ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 . ~~ ~~ December 9, 1998 Mr. D.W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Alpine Pool Rules Dear Chairman Johnston: In response to your request at the conclusion of the recent Alpine pool rule hearing, we are pleased to provide the following graphs: Alpine Oil Production Rates by Year, Alpine Gas Production Rates by Year, Alpine Water Production Rates by Year, Alpine Cumulative Oil Production by Year, Alpine Cumulative Gas Production by Year, Alpine Cumulative Water Production by Year, and Alpine Production Rate Forecast Summary. Each Plot is based on the currently approved 92 well development plan. For additional information or supporting documentation, please contact Mike Erwin at 265-1478. Sincerely, ~~ Mark Ireland ORIGINAL ARGO Iliaska of . . 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 Inun, 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- 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 File #6 12 ARCO Alaska Inc. : 13 · 14 15 16 17 18 19 20 21 22 23 24 25 · · . . 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 PUBLIC HEARING 3 In Re: } } } } 4 ALPINE OIL POOL 5 6 TRANSCRIPT OF PROCEEDINGS 7 8 Anchorage, Alaska December 3, 1998 9:00 o'clock a.m. 9 APPEARANCES: 10 commissioners: MR. DAVID W. JOHNSTON, CHAIRMAN MS. CAMILLE OECHSLI MR. ROBERT CHRISTENSON 11 MR. MARK IRELAND MR. DOUG KNOCK MR. MICHAEL D. ERWIN MR. DOUGLAS K. CHESTER MR. BRIAN RICHARDS * * * * * * Rr" ··~,t ¡ ~lf D t 751998 Naska Oil ~ "- '. Clb¿¡SC ",,1'>' ons. Cor.'''''1' . ''1nvnara.Ye 11",. laS/Oft MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 I Anchorage, Alaska 99501 (907) 276-3876 .. .. -. ORIGINAL .. u .. · II )1 I Ii II 1 II 2 I 3 I I 41 51 I I 6 II II Ii 7 II I 81 91 . . 2 PRO C E E DIN G S (On record - 9:05 a.m.) CHAIRMAN JOHNSTON: Well, good morning. It's a real pleasure to have everybody here today. I'd note the time is approximately five after nine o'clock, the date is December the 3rd, 1998, and we are located in the offices of the Alaska Oil and Gas Conservation Commission, located at 3001 porcupine Drive, Anchorage, Alaska. The head tables consists of myself, Commissioner Dave Johnston, and to my right is commissioner 10 Cammie Oechsli, and to her right is commissioner Bob 11 Christenson. These proceedings today will be recorded by Laura 12 Ferro of Metro Court Reporting. If you wish to receive a 13 · 14 15 16 17 18 II 1911 II 20 II II 21 Ii II 22 II i' 23 I I i 24 i II 25 I · transcript of these proceedings, we'd ask that you contact Metro directly. These proceedings are to consider an application by ARCO Alaska to define and establish pool rules for the Alpine Oil Pool. We are also here to hear testimony to consider an order -- an injection order authoring underground disposal in the general area. The commission published notice of the hearing in the Anchorage Daily News on October 16, 1998, and for the injection project on November 3, 1998. The hearing will be conducted, as usual, according to commission regulations, 20 AAC 25.540. Those briefly allow us to consider expert testimony. If you wish to be considered an METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 18 19 20 21 22 23 24 25 . . . 3 111 I 2 expert, of course we'd ask that you state your qualifications, and the commission will render a decision or a determination as 3 to whether we will consider you an expert in this matter or 4 not. 5 We will not necessarily allow questions from the 6 audience. If you do have questions though, we'd ask that you 7 write your questions on a piece of paper, get it up to the 8 front table here. If we feel it is germane then the commission 9 may consider asking that question of the applicant. And I'd 10 encourage you to do that at any particular time. You can 11 motion or somehow get the note up to us and we can take a look 12 at it at that time and make a determination. If not, we'll be 13 taking periodic breaks throughout the morning and that will 14 also provide an opportunity to get questions to us. 15 So I guess with that brief introduction I would like to 16 ask the spokesperson for ARca Alaska to identify themselves and 17 to provide the introduction to this morning's testimony. MR. IRELAND: Thank you, Commissioner Johnston. My name is Mark Ireland. I'm the development manager for ARca Alaska Incorporated, for the Alpine field, and I'll provide the introduction as well as being pressed into service on the reservoir section since our reservoir engineer is out of town today. I'd like to thank everyone for being here, commissioners and audience that's gathered as well. METRO COURT REPORTING, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 4 · 1 CHAIRMAN JOHNSTON: Before you proceed, Mark, since you 2 will be providing technical testimony, do you wish to be 3 considered as an expert witness and to offer sworn testimony? 5 MR. IRELAND: Yes, I guess I should be. CHAIRMAN JOHNSTON: Let me go ahead and swear you in 4 6 and then you can proceed with your testimony. If you'd raise 7 your right hand, please? 8 (Oath administered) 9 MR. IRELAND: I do. 10 11 sworn. 12 13 I · ¡ 14 CHAIRMAN JOHNSTON: Thank you. Consider yourself MR. IRELAND: Thanks. CHAIRMAN JOHNSTON: Please proceed. MR. IRELAND: Okay. First of all, I'd like to talk 15 about the name of the pool in the field we're involved with 16 today, and hopefully I won't trip over this too badly. But 17 there's been a number of different names incorporated in the 18 past. This is known as the Colville, also as Alpine, and 19 Alpine is the name that we're using for the reservoir section 20 today. The Colville River area is the geographical area where 21 we're located. The Colville River unit is the official unit 22 name that's been approved for the Colville River unit, and 23 I within the Colville River unit we'll be forming an Alpine 24 participating area sometime next year. So in order to maintain 25 consistency in our application for the pool rules, we're naming · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 5 · 1 the field after geographical area, the Colville River field, 2 and naming the pool after the reservoir, Alpine oil Pool. 3 As I mentioned, I'll cover the introduction and any 4 summary we need at the end. The section on geology, Doug Knock 5 will discuss; I'll also discuss the reservoir section; drilling 6 will be covered by Doug Chester, well operations by Mike Erwin, 7 the facilities section by Brian Richards, and we'll wrap things 8 up at the end. 9 This is a summary of the proposed pool rules. The 10 first being the field and pool name; second, the pool 11 definition; third, well spacing; fourth, drilling and 12 completion practices; fifth, reservoir surveillance; sixth, 13 regarding work-over operations; the seventh, automatic shut-in · 14 equipment; the eighth, production practices; the ninth, 15 gas-oil-ratio exemption; and the tenth, allowing for 16 administrative action. We'll be supplying testimony today in 17 I support of all the rules that we'll propose in this area -- in 18 these areas. 19 Our top priority with the Alpine development, we'll be 20 protecting the health, safety of human resources as well as the 21 environment while we're conserving the Alpine resources. These 22 proposed pool rules will prevent waste and promote 23 conservation. They will allow to protect correlative rights 24 and promote maximum, ultimate recovery. 25 Some brief background on the history of drilling in the · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . 6 1 Alpine area. The field was discovered in 1994 with Bergschrund 2 Number 1 well. In 1995 we drilled five wells, including side 3 tracks, the Alpine Number 1, I-A and 1-B, the Fjord Number 3 4 and 3-A. In 1996 further delineation drilling with the Alpine 5 3, the Bergschrund 2 and 2-A, the Nanuk 1, and Neve 1 wells. 6 Last year we saw the first two permanent development wells 7 drilled from the ultimate pad locations. Those are the CDl-22 8 well and the CD2-35 well. 9 The ownership in the field. The royalty owners, the 10 state of Alaska, as well as the Arctic Slope Regional 11 corporation. On the working interest side, ARCO Alaska 12 Incorporated, with 56%, as well as controlling the 22% that 13 Union Texas Alaska owns, along with Anadarko Petroleum . 14 Corporation with 22%. So effectively ARCO controls 78% of the 15 working interest. 21 22 23 24 25 . 16 with that brief introduction, if there aren't any 17 questions, I'll turn our testimony over to Doug Knock, who will 18 speak to the geology. 19 CHAIRMAN JOHNSTON: If you'd like to raise your -- I 20 assume you wish to offer sworn testimony? MR. KNOCK: Yes, I do. CHAIRMAN JOHNSTON: Raise your right hand, please. (Oath administered) MR. KNOCK: I do. CHAIRMAN JOHNSTON: Consider yourself sworn. Do you MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 7 1 wish to offer expert witness? 2 MR. KNOCK: Yes, I do. 3 CHAIRMAN JOHNSTON: If you would state your 4 qualifications. 5 MR. KNOCK: I've worked for ARCO for 11 years as a 6 petroleum geologist. I've worked on Prudhoe Bay, Kuparuk, and 7 on Alpine for the last year. I have a bachelor's degree from 8 the University of Idaho in geology, I have a master's degree 9 from the University of Alaska - Fairbanks in geology. 10 CHAIRMAN JOHNSTON: Any objection? COMMISSIONER OECHSLI: No objection. 11 12 COMMISSIONER CHRISTENSON: No objection. 13 CHAIRMAN JOHNSTON: Thank you, Mr. Knock. We'll · 14 consider you an expert witness in this matter, and I always 15 like to recognize a University of Alaska graduate. It's nice · 16 to see this state produce some technically qualified people. 17 MR. KNOCK: Thank you very much. I've got three major 18 topics to discuss this morning. Listed here, Alpine pool 19 geology, then I'll touch on cretaceous annular disposal 20 geology, and triassic waste disposal injection geology. 21 Rule 1. Pool rule number 1 is simply the field is the 22 colville River field, and the pool is the Alpine oil pool. 23 Here's an Alpine oil pool location map. Alpine is located 24 approximately 25 miles west of the Kuparuk River unit. The 25 Colville River unit surrounds the Alpine oil pool. To the left MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suüe 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · 11 . . 8 1 of the diagram the NPRA boundary is the Nechelik channel of the 2 Colville River, going through the western half of the Alpine 3 oil pool. This map shows in hatchered pattern the proposed 4 Alpine oil pool sections that we are asking the rules to apply 5 to. They fall entirely within the Colville River unit in red 6 outline there. 7 CHAIRMAN JOHNSTON: And does the oil pool boundary, at 8 least as far as you are aware of the -- those boundaries on the 9 evidence that you've gathered to date, fall entirely within 10 that hashed section? MR. KNOCK: The commercial limits, as we believe them 12 to date, fall within the hatchered pattern. 14 13 CHAIRMAN JOHNSTON: Okay. MR. KNOCK: This is a type log from the Bergschrund 1 15 well. The Alpine sandstone is the uppermost, upper Jurassic 16 sandstone in the Colville Delta area. The Nechelik, Nuiqsut, 17 Alpine, Kuparuk, and Torok sandstones -- Torok interval, are 18 all oil-bearing in the Colville Delta area. Only the Alpine 19 sandstone has been found to contain commercial quantities of 20 hydrocarbons to date. 21 22 any Ivishak? CHAIRMAN JOHNSTON: Is there any -- have you discovered 23 :: II MR. KNOCK: There's two penetrations of the Ivishak in the Colville River Unit, and it is very high water saturation, perhaps 75% and greater water saturation in the Colville River METRO COURT REPORTING, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 9 1 unit. 2 CHAIRMAN JOHNSTON: And where would you put the Ivishak 311 generally on this? 4 MR. KNOCK: Oh, it's Triassic, it's about 1000 feet 5 below the Nechelik. I've got a diagram later that will show 6 that. 7 Pool rule number 2. The Alpine pool is defined as the 8 accumulation of oil and gas common to and correlating to the 9 interval found in the Bergschrund #1 well between the measured 10 depths of 6876 and 6976. 11 CHAIRMAN JOHNSTON: And would you point that out again 12 for the benefit of..... 13 15 MR. KNOCK: I will. 14 CHAIRMAN JOHNSTON: .....the audience? MR. KNOCK: I've got a diagram right here that is an 16 Alpine oil pool type log from the Bergschrund 1 well. The 17 Alpine pool is shown to the left of the diagram. It is 18 bracketed on the top by the top Alpine pick, based on gamma ray 20 also based on gamma ray and resistivity. Alpine is a quartz 19 and resistivity logs, and on the base by the Kingak E marker, 21 rich, very fine defined grain sandstone, very well sorted -- 22 well sorted and locally glauconitic. 23 CHAIRMAN JOHNSTON: On your Exhibit 3, if you could 24 flash that up? 25 MR. KNOCK: Dh-huh, put that back up. It's right here. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 10 · 1 CHAIRMAN JOHNSTON: Is this your pool limits from this 2 point to where,..... 3 MR. KNOCK: Yes. 4 CHAIRMAN JOHNSTON: .....up there? 5 MR. KNOCK: Yes, from the marker you pointed to, to the 6 marker right above where it says Alpine sandstone, down to the 7 marker below that is the same as Exhibit 4, correct. 8 CHAIRMAN JOHNSTON: Thank you. 9 MR. KNOCK: This is a top Alpine structure map. Alpine 10 is largely a stratigraphic trap with up-dip pinch-out to the 11 northeast. Northeast being here. Pinched out into shales of 12 the Kingak. The faults are generally northwest trending, 13 generally down to the west normal faults with small throws · 14 small offsets averaging 20 to 30 feet. No oil-water contact or 15 gas-oil contact has been found in the field to date. 16 And that concludes my Alpine oil pool discussion. 17 CHAIRMAN JOHNSTON: Let me ask you a few questions. If 18 you could put Exhibit 5 back up on the screen? What do you 19 know about these faults that cut through the area? 20 MR. KNOCK: They're pretty small in offset. Alpine 21 is ranges in thickness from 20 to over a hundred feet. 22 Generally the 20 to 30' kind of offsets we're not really 23 concerned about as being major barriers to flow. These faults 24 cut down through the Sag River marker which is an excellent 25 seismic reflector, about 1000 feet below Alpine. They are a · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 11 · 1 little bit larger in offset at that deeper reflector, and they 2 become smaller in offset, shallower in the section as you go up 3 through Alpine. 4 CHAIRMAN JOHNSTON: So you don't see that the faults 5 would provide any compartmentalization? 6 MR. KNOCK: Not -- certainly not like the Kuparuk field 7 and not like parts of the Prudhoe field where we've got more 8 continuous faults with bigger offsets. 9 CHAIRMAN JOHNSTON: And how would you characterize the 10 sediments in the pool area in terms of strike-dip? And could 11 you kind of establish the regional setting for me a little bit? 12 MR. KNOCK: These are Elsmarian (ph) sands, derived 13 from a northern source area. They are shallow marine sediments · 14 that are elongate in an east-west direction. 15 CHAIRMAN JOHNSTON: When you say there's up-dip 16 pinch-out to the northeast..... 17 MR. KNOCK: Northeast, largely onto a structure 18 generally known as the Colville high -- towards the Colville 19 high. 20 CHAIRMAN JOHNSTON: So what kind of dip are we talking 21 about in this area? 22 MR. KNOCK: Very gentle, one to two degrees dip to the 23 south and southwest. 24 CHAIRMAN JOHNSTON: Thank you. 25 MR. KNOCK: I've got a little bit to say on annular · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Sevelllh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 12 · 1 disposal geology now. We plan to set surface casing at 2350' II 2 I subsea TVD at Alpine. And below that will be open annulus down I 3 I to the next casing string which will be down at the Alpine 4 level. The annular disposal interval is comprised mostly of 5 the Seabee formation and perhaps the upper part of the Torok. 6 The interval is interbedded sandstone and shale. It is highly 7 correlatable across the Alpine pool area. The interval above 8 the disposal interval, we're calling the upper barrier, is the 9 Schrader Bluff formation. It's a thick sequence of shale and 10 siltstone. And permafrost is continuous at 800 to 985' thick. See, surface casing is right there in red. That's at · 14 2350' subsea. Below that is the Seabee formation of shale wall 11 12 about. 13 well. Next is a diagram showing some of what I just talked This is annular disposal type logs, the Bergschrund 1 15 member. It's characterized by thin sands within an overall 16 shaley sequence, 1800' thick. Below that is the Torok 17 formation. We're calling that the lower barrier. That's at 18 least 700' of marine shale, prior to hitting any significant 19 sandy sequence. The upper barrier is 500' of shale and 20 interbedded volcanic ash in the lower part of the Schrader 21 i Bluff formation, and above that is 500' of siltstone with thin 22 coal interbeds, also part of the Schrader Bluff. And then at 23 the top of the diagram you can see permafrost. In this 24 I particular well is down to 850'. 2511 I CHAIRMAN JOHNSTON: What do we know about water quality · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 13 1 in this area? 2 MR. KNOCK: The total dissolved solids by the log 3 measurements we have done are 10,000 parts per million and 4 greater, based on our petrophysicist looking at several points 5 below permafrost on down into the Torok. So generally that's 6 unpottable, briny water, if you will. There's no drinking 7 water present. 8 CHAIRMAN JOHNSTON: And what has been your experience 9 to date with annular disposal? 10 MR. KNOCK: Just my knowledge of ARCO's other 11 operations on the Slope with annular disposal. I know what 12 they're doing at the Tarn location..... 13 CHAIRMAN JOHNSTON: So you don't have any personal · 14 knowledge about annular disposal in this immediate area as to 15 how it's gone for you, your success in putting fluids away, · 16 that sort of thing? 17 MR. KNOCK: To my knowledge in the Alpine pool area we 18 have not done annular disposal. 19 CHAIRMAN JOHNSTON: I guess we've authorized it but you 20 haven't actually done it yet, that's right. Okay. 21 MR. KNOCK: That's correct. 22 CHAIRMAN JOHNSTON: Okay. Thanks. 23 MR. KNOCK: Now I'm going to touch on Triassic waste 24 injection disposal briefly. In this coming February we will 25 drill the waste disposal #2 well. It's a Class 1 industrial MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 14 · 1 waste injection well. We have -- we will drill it down to 2 below the Ivishak sandstone. The lower injection zone will be 3 the Ivishak. The upper injection zone will be the Triassic Sag 4 River, and above that we've got a thick sequence of Kingak 5 shale which we are calling a confining and arresting zone. 6 I 7 I here's the location of the disposal well on a top Sag River I've got a diagram coming up that shows that. First 8 structure map. The well is 2500' or so from the Colville Delta 9 I pad 1, and over 1000' from any significant faulting. 10 Here is a waste disposal injection type log, in this 11 case the Fjord 1 well. The lower injection zone is the Ivishak 12 sandstone, very much different in the Colville Delta area than 13 it is over at Prudhoe Bay, much lower porosity -- 16% average · 14 porosity, 400' of gross sand. Above that is the Shublik 15 limestone, we consider that to be a barrier, and above that is 16 the Sag River sandstone which we're calling our upper injection 17 zone, averaging about 19% porosity, and 35' of net sand. Then 18 the Kingak shale, we've divided it into 700' of arresting zone 19 and 400' of confining zone, prior to hitting the upper Jurassic 20 Nechelik sandstone. 21 CHAIRMAN JOHNSTON: Let me explore with you some of the 22 terms that you're using here. Why are you calling this an 23 arresting zone; what's your logic there? 24 MR. KNOCK: We think that that shale, at a minimum, 25 slow down the growth of a vertical fracture. It's 700' thick. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Sevell/h Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · 9 10 11 12 13 · 14 15 · . . 15 1 There's really no magic in dividing the arresting zone from the 2 confining zone. This is classic ground water terminology, 3 hydrogeology. I would be just as happy with calling that 1100' 4 of confining zone. 5 CHAIRMAN JOHNSTON: Do you feel that you may propagate 6 fractures into this arresting zone? 7 MR. KNOCK: At this time we will initially perforate 8 only in the Ivishak interval to start with and..... CHAIRMAN JOHNSTON: The Ivishak interval's 79' thick. MR. KNOCK: That's 79'..... CHAIRMAN JOHNSTON: Or no, excuse me, net sand, right. MR. KNOCK: .....of effective porosity greater than 13% is what the 79' is. CHAIRMAN JOHNSTON: But you have 400' of gross sand. MR. KNOCK: We have a lot of sand with fairly low 16 porosity, and we will see how that goes, see what that will do 17 later. We may have to go in and add perfs and potentially add 18 perfs to the Sag River. But that's a thick shale, the Kingak 19 1100'. Like I said, I don't anticipate a large vertical 20 fracture extending up into the Jurassic sands. 21 CHAIRMAN JOHNSTON: So would you describe the Shublik 22 that you currently labeled as a barrier, would you describe 23 that as a confining zone for the lower injection in the 24 Ivishak? 25 MR. KNOCK: Limestones are pretty competent. They'd be METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 16 1 subject to brittle fractures, somewhat of a barrier, and 2 certainly very strong rock, very competent rock. In this case 3 the Shublik is actually a muddy limestone to a limey mudstone. 4 It's not a classic Lisburne kind of limestone, and that may 5 actually work in our favor with less brittle fracturing up 6 through it. But I would describe that as a confining zone to a 7 lesser extent than the Kingak. 8 CHAIRMAN JOHNSTON: So if you were injecting in the 9 Ivishak, you wouldn't necessarily be surprised if you saw fluid 10 appearing in the Sag River, above the -- is what you'd call a 11 barrier. 12 MR. KNOCK: Over time perhaps..... 13 CHAIRMAN JOHNSTON: Right. 14 MR. KNOCK: .....with fractures and natural fractures 15 in the limestone. 16 CHAIRMAN JOHNSTON: Right. Okay. What's the gross 17 thickness on the Sag River? 18 MR. KNOCK: 35 is -- it's pretty much 100% net to 19 gross. Well, let's see, maybe 40'. You may get -- I don't 20 think we've cut out a lot with the net sand there. I think 21 that the gross is slightly greater than 35. 22 CHAIRMAN JOHNSTON: So the Sag River could play a real 23 significant role for you in terms of disposal? 24 MR. KNOCK: It sure could. With the better porosity 25 and it is a consistent thickness amongst the wells that do go MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 17 1 down to Sag River in this area, it's a continuous sheet of sand 2 with a little better porosity than the Ivishak. 3 CHAIRMAN JOHNSTON: The faults that you showed on your 4 structure map, I don't see the exhibit number, but the one 5 immediately before that,..... 6 MR. KNOCK: Before this one? 7 CHAIRMAN JOHNSTON: Do those faults cut up through the 8 entire stratigraphic column? 9 MR. KNOCK: A lot of them do. A lot of these faults 10 cut on up through the Alpine interval. They decrease in throw 11 as they go up section. At this level they're -- a lot of them 12 are 50' average offsets, and then at the Alpine level 20 or 13 less in some cases. Actually there's more faults here so · 14 there's some that do not cut up, but some of the major ones do. · 15 CHAIRMAN JOHNSTON: So that your point of disposal 16 injection in your Nechelik 1 well, what did I understand you to say that you have at least 1000' offset there between..... MR. KNOCK: Yes. 17 18 19 CHAIRMAN JOHNSTON: .....from your known fault, and 20 that's at your point of disposal? 21 MR. KNOCK: That's correct. This is -- the scale of 22 this map, one inch is equal to 5000, that's approximately half 23 an inch or a third of an inch to that fault, it's well over 24 1000' to that fault, perhaps 2000, looking at that scale. 25 We've looked at the seismic and don't see any -- any large MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . '. 18 · 1 faults that -- or any small faults, for that matter, that 2 aren't mapped that aren't shown on this map. Well, in fact the 3 over- -- I don't know if it's on this overlay or not, no 4 they're not the same scale, not quite. But here on the Alpine 5 level that well would draw (ph) right about there to the east 6 of pad 1, and you can see that that particular fault that I had 7 at 1500, 2000' away, we have not mapped it at the Alpine level 8 in this case. 9 CHAIRMAN JOHNSTON: So that may be an example of a 10 fault that does not necessarily..... 11 MR. KNOCK: Right. 12 13 · 14 15 I'll be 16 today. 17 CHAIRMAN JOHNSTON: Thank you. MR. KNOCK: Thank you. MR. IRELAND: Hello. I'm Mark Ireland once again, and discussing the reservoir section of our testimony CHAIRMAN JOHNSTON: And I assume you wish to be 18 considered an expert witness? 19 MR. IRELAND: Yes, that would be appropriate. 20 CHAIRMAN JOHNSTON: If you'd like to state your 21 qualifications for us? 22 MR. IRELAND: Certainly. I have a bachelor's and 23 master's degree in petroleum engineering from Penn State 24 University. I've worked with -- for ARCO for over 15 years in 25 various Lower 48 locations. In the last 5~ or so years in · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · 1 Alaska, 2 fields. 3 4 5 · · . . 19 working on Prudhoe Bay, Pt. Mac, Lisburne, and Alpine CHAIRMAN JOHNSTON: Thank you. Any objection? COMMISSIONER CHRISTENSON: No objection. COMMISSIONER OECHSLI: No objection. 6 CHAIRMAN JOHNSTON: The commission will consider you an 7 expert witness, Mr. Ireland. Please proceed. 8 MR. IRELAND: Thank you. Some of the topics I'll be 9 talking about in the reservoir section now will be the 10 reservoir properties, recovery mechanisms, development plans, 11 future optimization plans, and then the proposed pool rules 12 that apply. 13 The reservoir property, the average porosity and 14 permeability are not quite as high as some of the other fields 15 in the North Slope. We have about 19% porosity. permeability 16 is generally less than 100 millidarcies, on average probably 17 quite a bit less than that. The initial average water 18 saturation, 19%. We have approximately a billion barrels of 19 oil in place, high quality oil, 39° API. The initial pressure 20 well above the bubble point pressure resolving in no gas cap 21 and no aquifer found to date. 22 In evaluating the best recovery mechanisms for the 23 field a number of different options were looked at: Primary 24 recovery, water flooding, lean gas injection, as well as 25 miscible injection. The result of these studies were to select MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · 11 12 13 · 14 15 16 · . . 20 1 water import with gas re-injection as our current plan of 2 developments recovery mechanism. This is based on ultimate 3 recovery as well as the economics of the process. The major 4 I risk we still see in the field is lower than expected water 5 injectivity. In that case that we have an insufficient amount 6 of water injectivity, we have a contingency plan, the ability 7 to convert the waterline from Kuparuk over to Alpine to gas 8 service. 9 This is a look at some of the recovery curves that were 10 generated during the course of this study. You can see ranging over a 30-year or so lifetime of -- from 35 to 45% recovery basically with the downside lower injectivity waterflood case giving the poorest recoveries and upside waterflood performance with the gas re-injecting -- re-injection, giving one of the highest recoveries. The current plan of development, broken into two 17 phases, the core area, central part of the field which has the 18 best quality rock and is also located closest to the two drill 19 sites that will be placed in the field, the core area develop 20 -- what we call the core area there would be developed with 50 21 wells and sort of a 600 millidarcy foot permeability thickness 22 cut-off to define that core area. 32 of those 50 wells would 23 be 'horizontal wells, giving 275-acre spacing for those 24 horizontal wells. The remaining 18 wells would be vertical 25 wells on 160-acre spacing. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuÏJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 21 · 1 2 between 3 feet. 4 field. The second phase being the peripheral area, that area a permeability thickness of 600 alt- -- 200 millidarcy There would be 42 wells drilled in that part of the They would be all vertical wells on 160-acre spacing. 5 The plan would be to inject water and waterflood the core area 6 and utilize the solution gas by re-injecting it around the 7 periphery. 8 That's our current base plan of development. And since 9 the time that was put in place we've been continuing to study 10 the field, gather data and look at additional ways to optimize 11 the recovery and economics of the field. We're currently 12 hopeful that by next year we may win approval for a proposed 13 our currently proposed revised plan of development. In this · 14 case we would increase the number of wells in the field, reduce 15 the spacing, as well as change our depletion plan. In this 16 case the core area of development, we're looking at 82 wells 17 drilled in that core area, and making those all horizontal 18 wells which results in 140-acre spacing. If you remember for 19 the current plan, that's 275-acre spacing for the horizontal wells, and now we've also got all wells in the core area horizontal versus originally part of those -- some of those 20 21 22 wells would be vertical. 23 The second phase, then going out with another 56 24 horizontal wells on 140-acre spacing again, this 140-acre 25 spacing in the core of the field results in approximately 1500 · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 22 · 1 foot inter-well spacing between rows of injectors and 2 producers. In this case we also hope to initiate a miscible 3 water alternating gas injection EOR project at the start of the 4 field if everything goes well, and that would be utilized in 5 the core of the field with the gas being -- not having enough 6 gas probably to start that process in each pattern across the 7 entire field, we'd start in the core and work our way out. 8 CHAIRMAN JOHNSTON: So let me understand this 9 correctly. You have a current development plan which, I 10 assume, the working interest owners have already agreed to, and 11 a proposed development plan. 12 MR. IRELAND: Correct. 13 CHAIRMAN JOHNSTON: And what's the difference between · 14 the two other than -- I mean what's the bottom line difference? 15 I mean why is not the current development plan the way to go? 16 MR. IRELAND: Revised plan of development could result 17 in higher ultimate recovery due both to increased number of 18 wells drilled, as well as going from the waterflood to the 19 miscible process in the field. 20 CHAIRMAN JOHNSTON: If it can result in higher ultimate 21 recovery then why is it a proposed plan? 22 MR. IRELAND: It's -- we haven't completed those 23 studies. There's at the same time there is potentially 24 greater benefits, there's also potentially greater risk. The 25 current plan that's in place has been funded and approved, · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 23 1 sanctioned by all the working interest owners, and has been as 2 well part of -- was the plan of development for unit filing 3 that's been approved. So we have more technical work to do, 4 plus gain the necessary approval from the working interest 5 owners, as well as other parties involved with the unit. 6 CHAIRMAN JOHNSTON: So what is needed then to move from 7 a current development plan to a proposed? I mean is the 8 decision going to be based upon actual drilling as you proceed 9 or..... 10 MR. IRELAND: That would be a part of it, but it's more 11 technical studies that need to be completed, then followed by 12 further economic analysis, and then gaining the approvals that 13 I mentioned. 14 CHAIRMAN JOHNSTON: Okay. When do you anticipate 15 completing these technical studies? 16 MR. IRELAND: We hope to have the new plan of 17 development -- of course the current economics in the industry 18 are not as favorable as they were previously, but if everything 19 works out well, and hopefully by next summer we could have a 20 new plan of development in place. 21 CHAIRMAN JOHNSTON: And I assume it would be your 22 intent to present this to the commission? 23 MR. IRELAND: Certainly. 24 CHAIRMAN JOHNSTON: Thank you. Oh, one more question. 25 In terms of your current development plan, what type of time MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 24 1 frame are we talking about here? Is this a one year, two year, 2 three year type development scheme? 3 MR. IRELAND: The development would cover the life of 4 the field, but to drill all the wells would take approximately 5 five years with a one rig development program..... 6 CHAIRMAN JOHNSTON: So is..... 7 MR. IRELAND: .....or the current plan. 8 CHAIRMAN JOHNSTON: Is that to drill all the wells 9 under both Phase I and Phase II? 10 MR. IRELAND: Right. Approximately five years. CHAIRMAN JOHNSTON: Okay, then what's the logic then in 11 12 presenting it as a Phase I, Phase II option? 13 MR. IRELAND: Just that the first phase would represent · 14 what we would expect to be the best performing wells in the 15 field, so that would be where we would concentrate our initial · 16 -- will concentrate our initial drilling. 17 CHAIRMAN JOHNSTON: So how long..... 18 MR. IRELAND: The second phase is as you get out to the 19 boundaries of the field it has the poorer quality rock, the 20 lower KH, as well as those are more expensive wells as you get 21 farther away from the drill site. So the economics of those 22 wells are not as firmly established as they are in the core 23 area -- Phase I core area. 24 CHAIRMAN JOHNSTON: So what then is your time line on 25 Phase I? MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 25 1 MR. IRELAND: Phase I would probably take approximately 2 three years to drill all of those wells. 3 CHAIRMAN JOHNSTON: And then your Phase II then? 4 MR. IRELAND: Another two years or so. 5 CHAIRMAN JOHNSTON: Another two years beyond that? 6 MR. IRELAND: Yeah. 7 CHAIRMAN JOHNSTON: And would those same time lines 8 apply for the proposed revised plan? 9 MR. IRELAND: with the greater number of wells, the 10 time line would be expanded to drill all the wells in the 11 development plan. 12 CHAIRMAN JOHNSTON: And so you wouldn't necessarily 13 have additional drill rigs? 14 MR. IRELAND: Not necessarily, no. 15 CHAIRMAN JOHNSTON: But of course it is an option, I 16 guess? 17 MR. IRELAND: Could be an option, yes. 18 CHAIRMAN JOHNSTON: Okay. Thank you. 19 MR. IRELAND: Sure. As we continue to study the 20 opportunity for a revised plan of development, we're also 21 looking for further optimization beyond that plan, and some of which will be evaluated here in the coming year with some of 22 23 our first wells in the field. 24 Multiple target wells are one of the first areas and 25 the opportunity here is to develop more of the reserves of the MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 26 1 field that will lower development costs. Longer horizontal 2 wells, the wells in the plan now are 3000' long horizontal 3 wells aligned in a line drive type of pattern. If we can drill 4 a 7000' horizontal well, we would cover all that area of two 5 wells with one well and reduce costs in that manner and also be 6 able to access more of the peripheral reserves that may not be 7 economic otherwise. 8 Another opportunity to accomplish the same thing is 10 penetrates the formation and then kicks out in one direction 9 with the multi-lateral well, and that would be a well that 11 down the line and then comes back and kicks out in the other 15 17 18 19 20 21 12 direction in approximately 3000 or 3500' in each direction. The 13 result of both those type of wells would be approximately six · 14 or 7000' of open reservoir section. · Infill drilling, something that is continued to look 16 at, and that's really one of the key components of the revised plan of development is the infill drilling, going from 3000' interwell spacing to 1500'. And then miscible injection optimization, assuming we gain sanction for the miscible project, then the optimization there, the MI enrichment level, the reservoir pressure, 22 operating the field at during the flood, how do we expand the 23 MI, as we recycle gas through the field and come into larger 24 volumes being available for injection. And then also the WAG 25 ratios during the flood and the length of cycles of the gas and METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 27 1 water injection would be further optimized. 2 CHAIRMAN JOHNSTON: Under your current development plan 3 when would you begin water injection? 4 MR. IRELAND: We'll begin very near to start-up. As 5 quickly as possible after start-up. We'll need to actually 6 utilize our water import pipeline for fuel gas to be able to 7 start our plant up. As quickly as we have our plant lined out 8 we'll switch that service over to water and begin injection. 9 CHAIRMAN JOHNSTON: So basically from the get-go on 10 water. What about the possibility of gas re-injection? 11 MR. IRELAND: Gas produced in the field will be 12 re-injected into two wells at start-up. 13 CHAIRMAN JOHNSTON: I thought there was a proposal to · 14 bring some of that gas to Nuiqsut? 19 20 21 22 23 24 25 · 15 MR. IRELAND: Nuiqsut has the opportunity of very, very 16 small volume. 17 CHAIRMAN JOHNSTON: Their volume would not necessarily 18 significantly impact the amount that you..... MR. IRELAND: No, you're talking about a couple hundred cubic feet per day versus the millions of cubic feet that we'll be producing. CHAIRMAN JOHNSTON: So that would just be for purposes of maintaining pressure in the reservoir, you wouldn't -- there's no -- under the current development plan there's not necessarily a hard proposal for miscible flood. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . . . 28 1 MR. IRELAND: Correct. 2 CHAIRMAN JOHNSTON: But the miscible flood may develop 3 as you get more reservoir data? 4 MR. IRELAND: Yes, and further studies completed. 5 CHAIRMAN JOHNSTON: So that may -- you may proceed with 6 a miscible flood even under the current development plan, not 7 necessarily the revised. 8 MR. IRELAND: I guess that would be one way of looking 9 at it, although if we do switch to a miscible flood, I'd 10 consider that a revision in the current plan of development. 11 CHAIRMAN JOHNSTON: It would be a revision, but not 12 necessarily -- you wouldn't be adding a lot more wells like 13 what we're seeing? 14 MR. IRELAND: That would be a possibility. Those are 15 somewhat independent decisions. 16 CHAIRMAN JOHNSTON: In terms of getting miscible 17 injectant, assuming that you go that route, where would you be 18 acquiring the..... 19 MR. IRELAND: We're evaluating sourcing our miscible 20 injectant from the field itself. Our oil is very amenable to 21 that process, very high gravity, light oil. The solution gas 22 from the field is very rich. So by stripping some additional 23 liquids from the fuel gas that we burn and recombining that 24 with the injection stream, we should be able to achieve 25 miscibility in the reservoir with just our own source of gas. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 29 1 CHAIRMAN JOHNSTON: Sounds promising. 2 MR. IRELAND: We're hopeful. The two rules following 3 under Reservoir Development, Rule 3. spacing, and Rule 9. GOR 4 Exemption, I'll show some further information on those. 5 On spacing units, because of the geometry of the 6 horizontal wells we're drilling, we're asking for no minimum 7 spacing, although not closer than 500' from ownership changes 8 at the boundaries of the pool. 9 On the GOR limitation, we're aSking for an exemption 10 from producing GOR limits, and I'll show a little more 11 information on each of these requests. The potential to need 12 to sidetrack some of these wells, especially the horizontal 13 wells where we wouldn't have sidetracking very far but we may 14 have problems with -- mechanical problems with the wells or 15 some reservoir problems, we may need to isolate high 16 permeability zones to manage our off-take of our flood, and 17 also may need to modify injector or producer profiles to 18 improve the recovery. Since these sidetracks will be very 19 close to the existing wells, we'd like to have the exemption 20 from spacing. 21 And then for Rule 9. the GOR Exemption, all of the gas 22 that we produce, minus any fuel gas burned or supplied to the 23 village of Nuiqsut, will be returned to the pool for pressure 24 maintenance and/or enhanced recovery. Also the water injection 25 process will maintain pressure and provide additional recovery MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . . . 30 1 as well. 2 That concludes my testimony for the reservoir section. 3 I'd be happy to answer any other questions. 4 CHAIRMAN JOHNSTON: Thank you, Mr. Ireland. I don't 5 think the commission has any questions currently for you, 6 although we may have later. 7 MR. IRELAND: Great. I'll turn it over then to 8 Doug Chester, who will cover the drilling section. 9 MR. CHESTER: Good morning. 10 CHAIRMAN JOHNSTON: Good morning. Do you wish to offer 11 sworn testimony today? 12 MR. CHESTER: Yes, sir. 13 CHAIRMAN JOHNSTON: If you'd raise your right hand 14 please. 15 (Oath administered) 16 17 18 sworn. 19 20 21 MR. CHESTER: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself Do you wish to be considered an expert witness? MR. CHESTER: Yes sir, I do. CHAIRMAN JOHNSTON: State your qualifications please. MR. CHESTER: My name is Douglas K. Chester, I'm a 22 drilling team leader with ARCO oil and Gas -- excuse me, ARCO 23 Alaska Incorporated. I received a bachelor of science degree 24 from Texas A & M in 1980. I've worked 17 years in the 25 industry, with experience in Texas, Louisiana, Oklahoma, MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · 9 10 11 12 13 · 14 · . . 31 1 Alabama, and Alaska, as well as offshore experience in the Gulf 2 of Mexico. My experiences include drilling production, 3 operations, and environmental safety and training assignments 4 over that time. I have worked for ARCO for 17 years, and of 5 that the last five, have been in Alaska. Three of those five 6 years were with ARCO/BP Shared Services Drilling, with 7 assignments in Endicott, Badami, and Prudhoe Bay. I have been 8 assigned to the Alpine project the last two years. CHAIRMAN JOHNSTON: Thank you. Any objections? COMMISSIONER CHRISTENSON: No objection. COMMISSIONER OECHSLI: No objection. CHAIRMAN JOHNSTON: Thank you, Mr. Chester. The commission will consider you an expert witness in this matter. MR. CHESTER: Thank you. I'd like to begin my 15 testimony with just an overall background on the drilling 16 practices that we'll be employing at Alpine. To begin with, 17 we'll be using 75' of conductor set at a minimum below the pad. 18 These will be insulated for frost subsidence around the 19 wellbores and to keep from having the frost subsidence problems 20 around the permafrost. Surface casing will be set below 21 permafrost and cemented to surface. We are proposing doing 22 single stage surface cement jobs, with top jobs and port 23 collars as our contingencies, and that's under current 24 practices on the Slope. BOPs will be installed and tested 25 before drilling below the surface casing. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 32 · 1 CHAIRMAN JOHNSTON: So the port collar is there in case 2 you have to do a second stage? 3 MR. CHESTER: That is correct. And that's essentially 4 consistent with current practices on the Slope at the present 5 time. 6 continuing 7 run" well design. on, we will use what we call a "bump and This will mean that in our intermediate 8 section we will drill through the Alpine reservoir, as we're 9 going to, horizontal. This will give us a top and bottom pick 10 of the reservoir when we drill it. We will set the 11 intermediate casing in the Alpine zone at horizontal or very 12 close to horizontal. We will perform formation integrity tests 13 in the zone. We will drill our horizontal section, swap out · 14 our drilling fluid to a diesel, and leave an open hole 15 completion. We will then run our tubing, is the current plan. 16 Our plans for surveys will be with MWD tools. Logging 17 will be with LWD in the zone. Current logging practices, drill 18 pipe conveyed in those type will be used as needed, but at 19 present the plan for logging will be with LWD, due to the 20 horizontal nature of the wells. We plan to batch drill, and 21 this is to reduce material storage, so at anyone time we may 22 be drilling a group of five or six surface holes, moving the 23 rig off and coming back and completing the wells at a different 24 time. With the remote nature of the site, this is an attempt 25 to kind of reduce our footprint and reduce the amount of · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 33 · 1 material needed to be stored at the location. 2 We plan on using a single BOP rig-up. This will be 3 done by a through bore wellhead system, and our horizontal 4 wellhead system will enable us to nipple up BOPs without -- and 5 do work-overs without nippling down flow lines and our wellhead 6 system. 7 Mud systems for the wells are typical North Slope 8 systems, and we propose no major changes in the mud. 9 COMMISSIONER CHRISTENSON: How are you going to leave 10 the wells in the (indiscernible)? 11 MR. CHESTER: We plan on leaving the wells at the 12 surface casing point. If we suspend at that place, we will 13 essentially bump our cement plug, do a pressure test on that · 14 string of casing. We will set our wellhead system, install a 15 back pressure valve, and essentially, what I'll call a dryhole 16 tree, which consists of a master valve left on the tree. So it 17 will be essentially secured. The same type of abandonment (ph) 18 would be used if we stopped and suspended an intermediate 19 casing point. The only difference would be you'd have the 7" 20 casing versus the 9%, but both casing strings would be tested 21 with a pressure test, verified that they're competent, set a 22 back pressure valve in the wellhead, and the wellhead surface 23 valve would be on the tree. 24 COMMISSIONER CHRISTENSON: Thanks. 25 MR. CHESTER: We have provided data to the EPA in our · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 34 . 1 Class 1 permit that we have no USDWs in this area, and there 2 was some discussion previous to that determination in earlier 3 testimony. We will have a ball mill capable of grinding and 4 washing gravel on location. This is -- the proposed plan is to 5 wash gravel, recycle it, use it as maintenance gravel, and then 6 inject through annular injection our wellbore muds cutting 7 fluids that were not recyclable. 8 The injection zone, as has been discussed earlier, is 9 to top the Seabee, the combining zone at Schrader Bluff, and we 10 have approximately 1000' below the West Sak. 11 Our pool rule request under Rule 4, we have requested 12 that upon drilling out no more than 50' into the Alpine 13 reservoir that we provide a formation integrity test, and the . 14 test pressure will not exceed a predetermined mud weight 15 supplied in the drilling permit application. The reason for 16 this is we don't want to create a fracture at the casing shoe 17 that could cause production problems or injection problems in 18 the future. This will determine that we have a competent shoe 19 and enable us to drill in the reservoir with a known pressure. 20 Our second request is we would like to be able to be 21 granted administratively completion and casing design program 22 changes. We believe the open hole in the slotted liner 23 completions that are proposed are the best completions at this 24 time. But with new information and in continued drilling there 25 may be other technologies that we will need to test and try, . METRO COURT REPORTING, INC. 550 West Seventh Avenue, SuÏle 1460 Anchorage, Alaska 99501 (907) 276-3876 · 8 9 10 11 12 13 · 14 · . . 35 1 and we would propose being granted that under drilling 2 permitting process. 3 Our C proposal is we would like to request going to a 4 two week BOP test period. Our reason for asking this is our 5 current time lines show that in the intermediate drilling plans 6 we come to casing point right about seven days in the Alpine 7 time lines. What this request would allow us to do is go ahead and run our casing at a very critical time in the well, not having to stop and do BOP tests or continually ask for waivers. We would hope that we could do this under a field rule request. On the D part listed, we are requesting that we submit under the Application to Drill to include a Plan D vertical section close approach, that and directional description. This will be essentially a reduction of paperwork between us and the 15 commission. These wellbores will be in the unit, and we feel 16 like this will enable you to have the information you need 17 without undue additional paperwork. 18 Our additional request is a complete electrical log and 19 radioactivity log will be required below the conductor to TD 20 for only one well on each drilling pad. This has been somewhat 21 of a current practice. We have fulfilled this obligation on 22 our first drill site with the 1-22 well. We would propose that 23 we do this when we go over to the second drill site, provide 24 the commission with a full suite of logs. And once that is met 25 we will supply reservoir type logs but not log service MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuÏJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 36 · 1 hole/intermediate hole unless it's -- there is a technical 2 reason to do so. 3 We also request and submit that we're providing 4 sufficient and appropriate disposal intervals at Alpine, or 5 have showed those. We would like to work under 25.080 for 6 annular injection, and we would like to essentially tell the 7 commission that we plan to use a particular well for annular 8 injection, and hopefully under the pool rules we have 9 demonstrated that annular injection is a viable injection 10 process at Alpine. 11 CHAIRMAN JOHNSTON: Why shall we not require more log 12 data than what you're proposing under D? 13 MR. CHESTER: with the Alpine reservoir -- or excuse · 14 me, with the close spacings and the general area we feel like 15 the one that is required will give us a baseline for whatever 16 is needed. We haven't seen a lot of other reasons for 17 additional logging up in the hole, as far as other horizons or 18 any of those type of opportunities. 19 CHAIRMAN JOHNSTON: In terms of -- how large an area of 20 the reservoir can you -- will you be developing from I guess 21 you're only using two pads, right? 22 MR. CHESTER: Yes, sir, that is correct. 23 CHAIRMAN JOHNSTON: So you're going to develop the 24 entire reservoir from two pads? 25 MR. CHESTER: That is our plan. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . . . 37 1 CHAIRMAN JOHNSTON: So that would only give us two 2 wells that have a complete suite of logs in them. 3 MR. CHESTER: Yes, sir. And most of the interval that 4 you'll be seeing is up in the upper part of the hole, which 5 from pad's area, that's more directly underneath the pad. 6 MR. KNOCK: 13 wells that already have complete logs on 7 the (indiscernible). 8 MR. CHESTER: And that is true. Mr. Knock brings to my 9 attention we have vertical wells around the field that do have 10 logs in them. So..... 11 CHAIRMAN JOHNSTON: Good. Thank you. COMMISSIONER OECHSLI: Doug, would you mind putting the 12 13 earlier slide up again? 14 MR. CHESTER: Which one? 15 COMMISSIONER OECHSLI: The earlier slide to this one. 16 MR. CHESTER: This one, the one before. 17 COMMISSIONER OECHSLI: Okay. I was just confused 18 because on the next page you had D also, and I wondered if it 19 was..... 20 MR. CHESTER: Did we miss A, B, C,..... 21 COMMISSIONER OECHSLI: .....left out, but it's not. 22 MR. CHESTER: .....D? 23 COMMISSIONER OECHSLI: No, it's just all there, just a 24 different..... 25 MR. CHESTER: I'm sorry. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 38 · 1 COMMISSIONER OECHSLI: No problem. 2 MR. CHESTER: You're right, there are two Ds. 3 CHAIRMAN JOHNSTON: I guess it's probably a little bit 4 appropriate to spend a little bit of time on this point number 5 C where you're requesting that BOPs be tested once every two 6 weeks. As you know, the commission has been in the process of 7 considering changes to its proposed regulations, and this was a 8 point that we considered in quite a bit of detail over the last 9 couple of weeks. We have at this juncture decided not to 10 change that requirement, to a two-week cycle, that we're going 11 to continue in our regulations to require a one week cycle. 12 And some of our reasons are -- one of the principal reasons for 13 me anyway, in terms of keeping the one because that -- I see a · 14 direct correlation between testing and maintenance of BOPs. 15 And so I see that there is a safety feature associated with the 16 one week cycle. Now, what I heard you say though is that that 17 doesn't necessarily fit in with your drilling schedules in 18 terms of your setting of surface casing and such? 19 MR. CHESTER: It would be more in the intermediate 20 casing. After we drill out of surface casing on a lot of our 21 projected plans right now, we would TD-ing our intermediate 22 hole. Roughly that's seven days after your BOP test. And 23 that's a very critical time from being able to once we TD the 24 hole, we desire to get casing in the ground as soon as possible 25 so we don't lose hole, conditions don't deteriorate. With that · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · 8 9 10 11 12 13 · 14 15 · . . 39 1 timing, as it's been discussed, the way we do that currently is 2 we call the commission and ask for a waiver. And that is what 3 we would probably do. The fact is that it's going to be a very 4 continuous type operation if we don't do this. So that's the 5 reasoning. 6 CHAIRMAN JOHNSTON: And if we don't allow this waiver 7 what is the effect? MR. CHESTER: We stand a chance of not being able to get casing to bottom, having to clean out a hole, having trouble getting casing to bottom which costs us time and money and inefficiencies. COMMISSIONER OECHSLI: Only if the waiver is not granted, right? MR. CHESTER: That is correct. CHAIRMAN JOHNSTON: But there is nothing to prevent you 16 from testing your BOPs earlier? 17 MR. CHESTER: That is true. And kind of the way it 18 breaks down right now, that would be like four days in with how 19 we would drill Alpine and how we have seen in the past is we 20 will only make one trip before TD. In other words, we'll put a 21 bottomhole assembly in the hole and we'll drill to our kick-off 22 point. We will trip, we would have to test that, and that's 23 roughly a four-day interval. So the timing is what -- we'd 24 either have to test it there or test it at TD. Those would be 25 the times of our trips. In the optimized drilling world, so to MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 40 · 1 speak. 3 CHAIRMAN JOHNSTON: Thank you. COMMISSIONER OECHSLI: Doug, could you clarify for me 2 4 under subsection -- the last one, I guess F, what exactly 5 you're asking the commission to waive with respect to annular 6 disposal? 7 MR. CHESTER: We just want to go on record that we have 8 submitted to you all of the, what I'll call, background and 9 pertinent data for annular injection, and be able on our APD to 10 say we plan to use A, B, C well for annular injection at a 11 permitting time, and after we have submitted to you data that 12 says this well is competent enough to be used for annular 13 injection, then it would be a granted piece at that time. · 14 This, hopefully, what we're proposing is that we supply you 15 enough of the background data that you can grant us annular 16 injection authorities submitted -- excuse me -- as long as we 17 submitted data that makes this well capable of being used for 18 annular injection. 19 COMMISSIONER OECHSLI: And with your permit to drill 20 would you submit the other data that's not related to the 21 geology at all, like the..... 22 MR. CHESTER: That's typically..... 23 COMMISSIONER OECHSLI: ..... (indiscernible - 24 simultaneous speech) and the volumes? 25 MR. CHESTER: .....done -- well, those are done after · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907,J 276-3876 . . 41 · 1 the well construction is started. So we're saying we'll tell 2 you that this well is being proposed for annular injection, we 3 wouldn't have to supply all of the data that says here's the 4 geology, here's what we will be putting in it. We'll have 5 addressed all of that here in this discussion, and then we will 6 have to essentially tell you that that well is competent for 7 annular injection after we've started the construction which 8 would be leak-off tests and cement job verifications, is our 9 proposal. 10 COMMISSIONER OECHSLI: All right. At what point would 11 you be letting the commission know what the volumes and 12 anticipated pressures are for that well? 13 MR. CHESTER: Well, the volumes is pretty much · 14 regulated as far as total cap of 35,000 barrels. Now the 15 leak-off test would have to be done after the well has been 16 cemented at the casing point, and that's kind of typically how 17 it's going now; we supply the commission with FIT and the 18 cement job verification. If it looks like the well is okay, it 19 has passed the criteria, then it would give you the opportunity 20 to approve that injection of that well -- on that well. I 21 guess what we're proposing here is we're not proposing anything 22 different from the regulation, all we're submitting to you now 23 is we would prefer to give you all of the information at once 24 for annular injection at Alpine, and then just submit to you 25 the competence data that you need to determine that this well · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · 12 13 · 14 15 16 17 18 19 20 21 22 23 · . . 42 1 can be used for annular injection or not. 2 COMMISSIONER OECHSLI: Okay, thanks. 3 MR. CHESTER: I feel like I've not answered that 4 appropriately. 5 COMMISSIONER OECHSLI: No, my hesitancy only has to do 6 with some, I think, procedural changes that are involved in the 7 proposed new regulation for annular disposal versus the old 8 one. 9 10 then? 11 That was the only reason for my hesitancy. CHAIRMAN JOHNSTON: Does that conclude your testimony MR. CHESTER: Yes, sir. CHAIRMAN JOHNSTON: Any further questions? COMMISSIONER OECHSLI: Not at this time. COMMISSIONER CHRISTENSON: Did you guys get this in your enclosure? COMMISSIONER OECHSLI: No, but it is included in the actual -- I think it's on page 25 of the (indiscernible) rules. It's not included with the oral testimony slides. CHAIRMAN JOHNSTON: Why don't we take a short break for about 10, 15 minutes. (Off record - 10:20 a.m.) (On record - 10:50 a.m.) CHAIRMAN JOHNSTON: .....we just finished up with 24 Doug Chester, and it appears that Mr. Erwin is in the hot seat. 25 MR. ERWIN: Yes, sir. METRO COURT REPORTING, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 43 . 1 CHAIRMAN JOHNSTON: I assume you wish to offer sworn 2 testimony? 3 MR. ERWIN: Yes, I do. 4 CHAIRMAN JOHNSTON: Would you raise your right hand, 5 please? 6 (Oath administered) 7 MR. ERWIN: Yes, sir. 8 CHAIRMAN JOHNSTON: Thank you. And do you wish to be 9 considered an expert witness? 10 MR. ERWIN: I do. 11 CHAIRMAN JOHNSTON: Please state your qualifications. 12 MR. ERWIN: I graduated from Louisiana State University 13 with a bachelor's degree in civil engineering in 1977. Have . 14 been employed as an engineer in the petroleum industry since 15 that time. I have 12 years of experience in the Gulf Coast, 16 from Alabama to New Mexico and offshore. The past 10 years 17 have been in Alaska, primarily at Prudhoe Bay, but the last 18 year has been -- I've been involved in the Alpine project. 19 CHAIRMAN JOHNSTON: Thank you. Any objections? 20 COMMISSIONER OECHSLI: No objections. 21 COMMISSIONER CHRISTENSON: No objections. 22 CHAIRMAN JOHNSTON: We'll consider you an expert 23 witness then, Mr. Erwin. Please proceed. 24 MR. ERWIN: Thank you. What I'd like to discuss this 25 morning is the well operations, work-overs and completions . MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 44 · 1 aspect, both of the Alpine producing and injection wells and, 2 as well as speak briefly to the Class II injection well permit 3 that we've sent in. And so I'll specifically speak to Well 4 Completions and Sidetracks, Reservoir Surveillance, which is 5 Rule 5; Work-over operations, which is Rule 6; Safety Valves, 6 covered under Rule 7; and then the Injection Well. 7 This slide is to depict a typical Alpine producer. The 8 default completion will consist of an open hole horizontal 9 segment, 6Va" diameter bit, over approximately 3000', as we've 10 described in our development plan. We'll have 16" conductor, 11 90/a" surface casing. 7" production casing will be directionally 12 drilled to achieve a horizontal set point within the Alpine 13 formation. The wells will be completed with a surface · 14 controlled subsurface safety valve below the permafrost, gas 15 lift mandrels for artificial lift, and 4~" tubing as a 16 standard. 17 The most common alternate completion will be 18 essentially the same with a 4~" slotted liner in the open hole 19 section. And that slotted liner will consist of alternately 20 blank and slotted pipe, depending on faults that are cut, any 21 exits that occur from the sand, and the actual length of the 22 wellbore configuration. But essentially the only difference is 23 the packer and liner hanger combination, along with the 4~" 24 slotted liner. 25 A typical injection well will almost twin the · METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suue 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 45 · 1 production wells, with the exception of the gas lift mandrels. 2 It will receive a different subsurface safety valve, one that 3 is not surface controlled, that is failsafe, that fails shut 4 and responds automatically to a reversal in flow, and would, 5 more often than not, be an open hole interval, although the 6 injectors could also receive a slotted liner, which is not 7 shown, just for simplicity. 8 We envision sidetracks as an integral part of the 9 overall development of the field. And an open hole completion 10 sets the stage for a primary cement job that would abandon the 11 open hole and allow us to kick-off of that cement plug to drill 12 a sidetrack which we envision would likely be cemented around a 13 smaller liner, and most likely drilled with coil tubing. That · 14 will allow us to come back and adjust the development and the 15 well pattern and the spacing configuration to meet -- just to 16 -- whatever reservoir problems or challenges develop as we 17 drill up the field. 18 Examples -- oops. Excuse me. Examples of some of the 19 common sidetracks could include accessing reserves that may be 20 trapped by faulting, sidetracks on an injector where perhaps 21 with newly emerging technology by resistivity at the bit, we 22 might go out and penetrate behind the waterflood front to 23 effectively expand the radius of an injection well and increase 24 the water injection rates. sidetracks that encounter 25 conductive faults that create problems in the flow patterns or · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 46 · 1 sidetracks that stop short of a potentially conductive fault. 2 Again, to enhance the reservoir sweep and performance of the 3 field. 4 Those lines are roughly to scale, and I think that 5 you'll see that from a spacing standpoint we can't deviate too 6 broadly from the existing spacing patterns without negatively 7 impacting the overall waterflood patterns and is a primary 8 reason why we're asking for the no minimum spacing requirement. 9 CHAIRMAN JOHNSTON: Are you going to be plugging back 10 on those before you do the sidetrack or..... 11 MR. ERWIN: I think it will depend on the situation. 12 There could be opportunities where you would enlarge your 13 injection area, for instance, by leaving the original open hole · 14 there. Certainly if it's to avoid conductive faults or 15 directional permeability changes, we would probably cement the 16 wellbore out. 17 Reservoir Surveillance, as a topic, is covered in 18 Rule 5. We're recommending initial static bottomhole pressure 19 be taken in all of the Class II injection wells. That would 20 represent approximately half of the total wells drilled and 21 would be our best source of initial static bottomhole 22 pressures. We envision an extended drilling period that would 23 allow for those initial statics to be taken throughout the 24 initial development of the field. We're requesting a minimum 25 limit of six statics per year, and that's because of the · METRO COURT REPORTING, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 47 · 1 inordinately long build-up times. In horizontal wells this is 2 a direct function of the well length. We'll focus our efforts 3 on obtaining static mostly likely and extrapolating build-ups 4 off or the injection wells. 5 I think what I'll do is jump ahead to this next slide 6 and show you why that -- why I'm recommending that. 7 This represents a computer model of the reservoir 8 pressure around a producer over the course of the first year, 9 producing at 3000 barrels per day in an average well at Alpine. 10 It may take a full year for the reservoir pressure to decline 11 to say 2500 pounds, but shut-in for a pressure buildup or a 12 static, this same one year period would suggest that out at one 13 year the pressure will have only recovered to approximately · 14 3100 psi after a year of shut-in. And so the traditional seven 15 day static that we take in other fields in a vertical 16 completion would not register an appropriate pressure 17 representative of the average reservoir pressure. 18 We're recommending that the reference datum for 19 reporting all static bottomhole pressures in the field be 20 7000', and that because of the relatively small number of 21 pressures being sampled each year that they be reported on an 22 annual basis rather than monthly. That 7000' datum corresponds 23 with roughly the heart of the field. This is a top structure 24 map for the Alpine with the 7000' contours shown in red. 25 Rule 6 concerns well work operations. We're requesting · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 48 · 1 that the following operations that would occur in production 2 and enhanced recovery wells within the pool may be conducted 3 without the initial application requested in 20 AAC 25.280(a). 4 In particular, that would free us up for perforating and 5 re-perforating, stimulating and performing coil tubing 6 operations not to include drilling or sidetracks without prior 7 approval from the AOGCC. You would still continue to receive 8 post-work summaries on all well work performed. 9 Rule 7 deals with automated shut-in equipment. An 10 automated surface safety valve will be installed on all wells 11 with testing proposed for six month intervals, and a notice 12 period to the commission. A surface controlled subsurface 13 safety valve will be installed in all new producing wells with · 14 testing on a one year frequency, coordinated with the 15 commission. At our discretion, we're asking that allowance be 16 provided for subsurface safety valve removal in marginal wells, 17 and we define those to be wells producing less than 1500 18 barrels per day and 5,000,000 cubic feet of gas. 19 CHAIRMAN JOHNSTON: Would those wells be capable of 20 unassisted flow to the surface? 21 22 23 24 25 time? MR. ERWIN: Yes, sir. CHAIRMAN JOHNSTON: They still would. MR. ERWIN: For a very brief time it would be possible. CHAIRMAN JOHNSTON: What do you consider a very brief · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuiLe 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 49 1 MR. ERWIN: I would expect hours not to exceed 24 until 2 the well is loaded up. 3 An automatic fail closed injection valve, which is not 4 surface controlled, would be installed in injection wells as a 5 subsurface safety valve with testing conducted on an annual 6 basis. 7 CHAIRMAN JOHNSTON: How are you going to be freeze 8 protecting the wellhead and the corresponding surface safety 9 valve equipment? 10 MR. ERWIN: Freeze protection on the producers will 11 consist of a kill weight brine with a diesel cap. The diesel 12 cap would be the freeze protection. We're looking at using 13 nitrogen perhaps on the injection wells. If not it would · 14 either be diesel or a nitrogen cap on the injection wells. · 15 CHAIRMAN JOHNSTON: I guess my question was not how 16 you're going to freeze protect the wells from the effects of 17 permafrost, but are you going to freeze protect the wellhead so 18 the surface safety valves -- you know, the pilots, the lines 19 and that sort of thing, do not freeze up? As I understand 20 are you going to have dog houses around these wellheads? 21 MR. ERWIN: Yes, sir. 22 CHAIRMAN JOHNSTON: Okay. So they will be enclosed? 23 MR. ERWIN: Excuse me one moment. Brian, are you able 24 to hear that? 25 MR. RICHARDS: Yeah. Do you want me to talk about MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuÏJe 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 50 1 that? 2 MR. ERWIN: If I could defer that to Brian 3 Richards,..... 4 CHAIRMAN JOHNSTON: That would be fine. 5 MR. ERWIN: It's specific -- it will fit better in his 6 area, David. 7 CHAIRMAN JOHNSTON: Right. 8 9 area? 10 11 MR. ERWIN: Were there any other questions in this COMMISSIONER CHRISTENSON: No. MR. ERWIN: I'd like to briefly address the Class II 12 injection well completion. This is the Sadlerochit disposal 13 well. We would again be setting 16" conductor, 95/8" surface · 14 casing here would be set slightly deeper than the producing 15 wells. We would be running a 75/8 by 7" production casing string 19 20 21 22 23 24 25 · 16 to -- and the tapered string is to provide for the thaw 17 protection in the -- through the permafrost. Heat tracing. An 18 injection valve, i. e. subsurface safety valve below the crossover, 4~" tubing, an isolation packer and then perforations in the target interval with cement backup and across the arresting and confining zones and above the Alpine. If there are no further questions, that concludes my testimony, and I'd like to turn it over to Brian Richards to discuss the facilities. CHAIRMAN JOHNSTON: I do have some questions, and it MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 51 · 1 may be best again for Brian, but let me put it out there 2 anyway. How would you describe the surface environment in this 3 particular location? I mean part of my concern, relative to 4 removal of subsurface safety valves, would be, you know, the 5 sensitivity of the surrounding environment. Clearly commission 6 regulations recognize the importance for the offshore 7 environment, and we have a requirement that subsurface valves 8 be installed. But onshore it's a different matter, there's no 9 firm criteria to require subsurface safety valves. It's been 10 commission practice, however, to require them in sensitive 11 areas. And the Colville Delta, I think in everybody's 12 consideration, is relatively sensitive environmentally 13 speaking, and an area that should deserve highest protection. · 14 So I note that you are in fact proposing subsurface safety 15 valves as a routine matter. 16 MR. ERWIN: Yes, we are. 17 CHAIRMAN JOHNSTON: But you do wish to remove them at 18 your discretion in these, I guess you described it as marginal 19 wells? I guess again I'm thinking what -- even though the well 20 may flow for a short period of time, what steps are you taking 21 to ensure that if there was a failure of the wellhead is there 22 any containment on the pad being proposed or how do you -- what 23 further steps are being taken to ensure that we don't have a 24 spill getting out into the waterways of the Delta and such? 25 MR. ERWIN: That's a very good question. It would be · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 52 1 best to defer that to Brian, who can address the facility and 2 surface. 3 4 CHAIRMAN JOHNSTON: Thank you. COMMISSIONER CHRISTENSON: Mike, do you expect the 5 watercuts to be significant when the wells get down to 1500 6 barrels a day, 5000? 7 8 rapid -- once the waterflood fronts do break through we'll see MR. ERWIN: Yes, sir, I do. We expect to see very 9 very rapid increases in the watercuts on the producing wells. 10 11 12 13 COMMISSIONER CHRISTENSON: Okay. Thanks. CHAIRMAN JOHNSTON: Mr. Richards. MR. RICHARDS: Good morning. CHAIRMAN JOHNSTON: And I assume you wish to offer · 14 sworn testimony? 15 16 17 please. MR. RICHARDS: Yes. CHAIRMAN JOHNSTON: If you'd raise your right hand, 18 (Oath administered) 19 20 21 sworn. 22 23 24 25 in 1977 · MR. RICHARDS: Yes, I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself Do you wish to be considered an expert witness? MR. RICHARDS: Yes. CHAIRMAN JOHNSTON: Please state your qualifications. MR. RICHARDS: I graduated from Iowa State University with a bachelor's degree in chemical engineering. In METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 53 1 the 21 years since then I've worked in the oil business for the 2 last 17 with ARCO, both in exploration and production and in 3 refining in Louisiana, Texas, the Gulf of Mexico, and a total 4 of 12 years in Alaska. I've been in Alaska the last eight 5 years in a variety of operations jobs; operations supervisor, 6 operations superintendent, and for the last two years I've been 7 an 8 9 10 11 operations representative on the Alpine Project Team. CHAIRMAN JOHNSTON: Thank you. Any objection? COMMISSIONER OECHSLI: No objection. COMMISSIONER CHRISTENSON: No objection. CHAIRMAN JOHNSTON: The commission will consider you an 12 expert witness in the matters that you're testifying for. 13 MR. RICHARDS: Okay. What I want to do is just real · 14 briefly -- let me switch mics. Everybody else has talked about 15 what's going on underground. I want to talk for just a couple · 16 minutes about what you might expect to see on the surface. 17 Alpine in this map here, we're right in the very middle of the 18 Colville Delta. The Colville comes from the south, and right 19 here is the main split, the east channel then goes up this way. 20 The main flow of the river comes up to here. The Nechelik 21 channel, to the west, goes over -- I can't read it upside down -- it comes right over here by the village of Nuiqsut, and then eight miles down river is where all of our facilities of 22 23 24 the field will be built, right here. 25 In this little circle blow-up over here you can see we MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 54 . 1 have two pads. As was described earlier, they are 2 approximately three miles apart. The pad the eastern most 3 pad has an airstrip right next to it, and it has the processing 4 plant and the camp. And the next slide I've got shows this 5 area a little bit more blown up, and you can see what is 6 immediately surrounding our location. 7 The pipeline routing for our seawater import and the 8 oil export goes south near Nuiqsut to the river crossing, and 9 then across country to CPF-2 where they tie in to existing 10 Kuparuk facilities. And some of the key things about Alpine is 11 that there will be no road that connects the Alpine field to 12 any other field. So there's no road along that pipeline. 13 Just a little bit of a more blown up view of exactly 4IÞ 14 where we're located. This is the west channel, the Nechelik 15 channel of the river. You see the Drill site 2 is 16 approximately -- I think this is roughly a half a mile from the 17 west channel, three miles to the east where the main pad is, 18 right there is the start of the air strip that goes here, and 19 then on this main pad there are three basic parts to this main 20 pad. There is infrastructure which is -- I'll talk about in a 21 second -- there's a processing plant and then the first drill 22 site with 40 wells in the proposed development plan and 23 possibly substantially more in the second plan that Mr. Ireland 24 talked about. And as you can see, there's substantial number 25 of lakes and rivers. This Sakoonang channel which is right . MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 55 · 1 adjacent to our plant location right here, my understanding, 2 without having seen this, it flows at breakup. Most of the 3 year it doesn't have flow, not active flow, but substantial 4 numbers of lakes all around. 5 On the infrastructure parts of the project is all the 6 things that I guess I'd say would be required to support the 7 oil without actually directly making oil: a camp for all the 8 people that are there to live in; warehouse and shop for 9 maintaining materials and for working on equipment; a wash bay 10 where we can clean equipment in a -- and recover all the water 11 that gets used for washing in a sound manner; a disposal well 12 for wastes; a runway for air support because nine months or 13 eight months a year air support will be our only way of getting · 14 in people and supplies. During the winter we can build ice 15 roads. But with no gravel roads the runway will be our only 16 supply route. Power generation for our own electricity and 17 telecommunications to get information both to Alpine and from 18 Alpine. 19 A brief description of what the plant itself -- the 20 processing plant is going to do, and what I've drawn here on 21 the outside, this dotted line in terms of a boundary for the 22 Colville River field, we really had one stream coming in and 23 two leaving the field. We have sea water we're going to import 24 from Kuparuk, and the two exports are sales oil, which go back 25 to Kuparuk, and tie into the Kuparuk platform system at CPF-2, · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 56 · 1 and then field gas to Nuiqsut. 2 And this -- you asked earlier about volumes. This is 3 roughly a half a million cubic feet a day out of our produc- 4 our planning capacity is over 100 million a day. So it's a 5 very small amount of exported gas there. 6 within the plant all the well fluids will come into oil 7 separation and processing, and basically this plant will do the 8 same job that a Kuparuk plant does; separate the oil for 9 make it sales grade. Water will go to disposal. We don't 10 expect significant produced water for a long period of time. 11 Gas off of the oil will be compressed and drived (ph), 12 conditioning is drying. It will have three uses: Fuel gas 13 will be burning gas for our turbines. We'll be re-injecting · 14 gas into the reservoir for pressure maintenance and we'll be 15 using it for artificial lift and the gas lift wells. 16 In the separation section of the plant there's three 17 main vessels. There's heating and cooling, shipping pumps and 18 metering, water disposal pumps, all the same type equipment 19 that's in Prudhoe and Kuparuk facilities. The one main 20 difference with the three oil vessels, Kuparuk typically has 21 either four or five vessels, and so ours is a much more 22 compact, simplified oil train. But while it's compact I want 23 to show this slide so you can see this is not -- it's a compact 24 development and plant, but it's not small equipment. This is 25 taken at our Kenai fab site a couple of weeks ago. This is our · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 57 . 1 main inlet separator where all the production fluid is going 2 into and it's slightly smaller than a Kuparuk vessel, but not 3 very much. It's going to have -- it's a compact plant but it 4 has large equipment. 5 COMMISSIONER CHRISTENSON: What does it weigh? 6 MR. RICHARDS: What's that? 7 COMMISSIONER CHRISTENSON: What does it weigh? 8 MR. RICHARDS: The vessel itself, I'm not sure. The 9 biggest module we have is roughly 1200 tons. 10 In the gas compression facility we have two main two 11 main parts. We have a low compression compressor which is 12 electric drill and a high pressure which is turbine driven, and 13 really the main key thing here is we only have one gas 4IÞ 14 compression train, so we're going to be the only facility on 15 the Slope that's 100% dependent on one gas compression train. 16 CHAIRMAN JOHNSTON: What happens when that -- if that 17 train goes down? 18 MR. RICHARDS: We'll be shut down till it's fixed. If 19 the big compressor goes down, we won't be able to operate. 20 CHAIRMAN JOHNSTON: So you shut-in wells? 21 MR. RICHARDS: Yeah. One quick slide on production 22 allocation. 23 basis for the 24 wells and the We anticipate using actual sales volumes as the well, but that would -- the number of horizontal development plan currently in place, actual 25 royalty allocation will be based on reservoir modeling. Using 4IÞ MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 58 · 1 individual well tests and downhole data collected by wireline, 2 but we're anticipating or we'd request in the -- for the first 3 year of production when the wells are actually, you know, come 4 on to initial production, we'd be testing them at least 5 monthly. After several months their production is going to be 6 very stable because we have -- we're going to be running, we 7 believe, at full open choke. We're not going to have capacity 8 limitations like both Kuparuk and Prudhoe have in our gas 9 train. These wells are going to be very stable. with the 10 number of wells we're going to have on each pad in the 11 long-term we're requesting that a quarterly test as a minimum 12 requirement thereafter. And we also do not have options that 13 Prudhoe Bay has in terms of the wells can flow into different · 14 systems on different days. We're going to be a very simple, 15 straight-forward one separation train, everything wide open 16 into it. 17 On freeze protection -- do you have any questions about 18 these slides? 19 CHAIRMAN JOHNSTON: I was just curious in terms of your 20 well testing frequency. Has that proposal been ran by the 21 royalty owners, have they agreed to that? 22 MR. RICHARDS: I don't know. Mike, can you help me? 23 No, I guess it has not been, no. 24 CHAIRMAN JOHNSTON: Okay. 25 MR. IRELAND: The royalties will be allocated off the · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 59 · 1 reservoir modeling, as Brian stated in kind of long-term 2 reserve picture versus the short-term daily production 3 (indiscernible). 4 CHAIRMAN JOHNSTON: But the allocation process has all 5 been agreed to? 6 MR. IRELAND: The process, yes. The final decimals, 7 tract allocations facing that work, no not yet. 8 MR. RICHARDS: On the question on freeze protection 9 that came up earlier. The injection wells will all have houses 10 on them. The production wells are not going to have houses. 11 Right now we're anticipating water break to be substantially in 12 the future. We believe that producing wells don't need them. 13 The first and primary method for freeze protection is going to · 14 be displacement with gas. We can also use diesel. To displace 15 we'll have a small amount of methanol that we can also use, but 16 since we can't supply -- resupply with methanol very 17 conveniently in the winter we -- or after the actual is out, I 18 mean we'll be trying to minimize the use of methanol. So gas 19 displacement and diesel displacement would be the two primary 20 means of freeze protection. 21 CHAIRMAN JOHNSTON: So what about ensuring that your 22 surface safety valve closes when you need it to close? I mean 23 we've seen a number of examples across the North Slope where 24 these valves can freeze up if they are not wrapped somehow. 25 Are you going to be wrapping these things in electric blankets · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . 60 1 and..... 2 MR. RICHARDS: Well, our intention hasn't been. No, we 3 don't believe that these wells are going to flow hard enough 4 you know, strong enough producing wells that we're not going to 5 have a and with no water production for the first several 6 years, and use wells that we won't have a problem with freezing 7 in the wellheads. 8 CHAIRMAN JOHNSTON: Interesting. You may have a 9 different situation here at Alpine than you do elsewhere across 10 the Slope because we've seen where if the operator does not 11 property wrap their surface safety system then it's possible 12 that it freezes up on them and will not close. 13 MR. RICHARDS: Okay. You're talking -- the pilot 4IÞ 14 systems, the controls as opposed to the valve..... . 15 CHAIRMAN JOHNSTON: That's what I thought the..... 16 MR. RICHARDS: .....itself, the problems have been with 17 freezing in the pilots? 18 CHAIRMAN JOHNSTON: Right. 19 MR. RICHARDS: All of our instrumentation is going to 20 be in the manifold buildings. We're not going to have any 21 instrumentation at the wellhead itself. 22 CHAIRMAN JOHNSTON: But the valve itself has got to 23 close. 24 MR. RICHARDS: The valve itself has to close, but the 25 problems that the other fields have had has always been with MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 61 . 1 the pilot systems as opposed -- and that's where the insulation 2 and the wrapping and the heat tracing has been -- and the 3 arrangement has been vertical. And we've moved all of that 4 instrumentation into the manifolds. Our wells are so close 5 together that they're relatively close to the buildings. So 6 that instrumentation will be encl- -- in the buildings. 7 CHAIRMAN JOHNSTON: That's what I was..... 8 MR. RICHARDS: Okay. 9 CHAIRMAN JOHNSTON: Now in terms of the other question 10 I had relative to the wisdom of taking out the subsurface 11 safety valves on your marginal wells. Could you fully expand 12 upon that, what additional steps may be incorporated in the 13 facilities to ensure that the -- if there was a failure that . 14 the oil would not -- there you go. 15 MR. RICHARDS: A couple of things about the pads 16 themselves. You can't see in this one anyway. But these pads 17 are all with the current storm water regulations, these pads 18 are all drained into what we're calling sumps. But basically 19 the pads -- historically the North Slope pads are graded flats 20 or control flow in the direction. Ours are controlling flow 21 into collection areas. So anything that gets onto the pad in a 22 substantial volume would flow into one of these collection 23 areas and we could contain it there and then remove it with 24 vacuum trucks or pumps. So the pads themselves are drained to 25 collection collection areas. . MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 62 1 CHAIRMAN JOHNSTON: So then you feel if there was some 2 other failure with the wellhead on these marginal wells that 3 the flow would be marginal, if at all, and that it would fully 4 be contained to the pad? 5 MR. RICHARDS: I don't know if they'd guarantee it 6 would be fully contained to the pad, I'm not sure I would say 7 that. But anything that was on the pad would definitely be 8 contained in any containment areas. And at these rates, I 9 don't think -- we don't expect rates to drop to that area until 10 we get water break. Right, Mike? 11 MR. ERWIN: That's correct. 12 MR. IRELAND: I'd ask for a short, five minute recess 13 before we continue? 14 CHAIRMAN JOHNSTON: That would be fine. That will give 15 us the opportunity to collect some additional questions. 16 (Off record - 11:25 a.m.) 17 (On record - 11:35 a.m.) 18 CHAIRMAN JOHNSTON: Back on record. Mr. Ireland, I 19 guess you're due to summarize. We also have a series of 20 questions. Do you wish to do your summary and then the 21 questions or..... 22 MR. IRELAND: That would be great, yes, if I could just 23 go ahead and summarize first. 24 Commissioners, I just mentioned that the reason we're 25 here this early prior to field start-up, which is not until the METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 63 · 1 year 2000, is really to provide drilling flexibility with our 2 horizontal development plan and so on. The key rules in that 3 regard, of the ten that are really critical prior to start-up, 4 I guess Rule 1, the field and pool name; Rule 2, the pool 5 definition; Rule 3, the well spacing is a key one, and Rule 4, 6 drilling completion practices; and then Rule 10, allowing for 7 administrative action on those. The other five rules, number 8 5, 6, 7, 8, and 9 really won/t come into play until the start 9 of production, and as such are not as critical to us for this 10 coming year. 11 We plan to be back in front of you again next year. As 12 I mentioned earlier, we are pursuing a new and hopefully 13 improved plan of development that will be able to put into · 14 action. At the same time we bring that information forward, we 15 would also apply for an area injection order to support that 16 plan of development and have that in place prior to start-up, 17 obviously. 18 I/d like to reiterate that our key concern for Alpine, 19 as operator, is for the health and safety of all people 20 involved directly or living near the development. The very 21 close -- closely related to that is our concern for the 22 environment. 23 I/d just like to follow-up for a minute the intent in 24 our request with the subsurface safety valves is to start with 25 subsurface safety valves in all of our wells. The request for · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 64 · 1 Rule 7 on the automatic shut-in equipment is to give us 2 flexibility in the future. Not that we plan to necessarily act 3 on that but to have that flexibility out there, to consider 4 removing that equipment and -- our criteria would really be for 5 wells that are incapable of flow. The criteria that we listed 6 in the rule itself was an attempt to approximate those 7 conditions, but really that's our intent would be not to have 8 removed that equipment from any well that was capable of 9 flowing to the surface. And perhaps we could modify that if 10 that would be more appropriate. 11 I guess I'd just finish my summary to say that the 12 Alpine owners are excited and eager to begin drilling this 13 winter. The five rules I mentioned are important to us to make · 14 that as efficient and effective as possible, and we're looking 15 forward even more to the start-up of production in the year 16 2000. Thank you. I'd be happy for any questions. 17 CHAIRMAN JOHNSTON: Thank you. I think we have a 18 series of questions, and I guess I would just open it up to 19 anyone of the individuals testifying as to who would be best to 20 answer that, it would be up to you to have that person slide up 21 to the microphone to respond. 22 My first question I have is in the Bergschrund sequence 23 above the Alpine, have you -- do you see any potential for a 24 hydrocarboning accumulation? 25 MR. IRELAND: Let me point that one to Doug Knock. · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suue 1460 Anchorage, Alaska 99501 (907) 276-3876 · 9 10 11 12 13 · 14 15 16 · . . 65 1 MR. KNOCK: I don't need to be sworn in again? 2 CHAIRMAN JOHNSTON: Yeah, you guys are sworn for the 3 duration. 4 MR. KNOCK: Good. Certainly there's hydrocarbon 5 potential in the Brookean (ph) sequence above Alpine. I'll see 6 if I can find an overlay that (indiscernible). Most of that 7 potential would lie in the interval that we call Torok, and 8 there have been core data gathered in the Torok. I believe the Torok sands there has been -- I may be stating this wrong, but in the Colville Delta area, I believe there's been an attempt at a well test or two in the Torok interval in the older Colville Delta wells. As I said before, it's oil bearing. There's a few sequences of sandstones within the Torok. The Torok is a thick sequence of prograding shales and clastics from west to east, and most of the sands that we've seen in the Alpine pool area or the Colville unit area are oil bearing. 17 They are generally a low porosity and low permeability. What 18 we've seen to date in the Colville unit area, certainly the 19 potential exists to come upon a more channelized turbidite 20 sequence than we've seen to date. I would say that we've got 21 13 penetrations or more in the Colville River unit that have 22 good log data across the Brookean sequence -- a complete set of 23 logs in most of those wells, if not all. I think on a 24 well-by-well basis we will be evaluating whether we need to 25 gather more data on the Torok. We don't want to be held to MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuÏJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 66 · 1 saying that we are going to acquire a full suite of logs on all 2 our development wells which are closely spaced coming down 3 through the section from 4- to say 6000'. We're pretty closely 4 spaced in at the pad and we don't feel we need that kind of 5 repetitious data everywhere. 6 CHAIRMAN JOHNSTON: But you do recognize that there may 7 be opportunities in the Torok that..... 8 MR. KNOCK: And we will be..... 9 CHAIRMAN JOHNSTON: .....cannot be ignored? 10 MR. KNOCK: Yes. We will be evaluating those 11 opportunities. Most of that work will be done by our -- an 12 extension exploration team. 13 with that work. · 14 CHAIRMAN JOHNSTON: I will be peripherally involved I think you'll find the commission 15 also interested in that, so periodically we'll probably want to 16 be sitting down with you and getting kind of an update as to 17 what your current understanding is and what evidence that 18 you've seen to date from the drilling and that sort of thing. 19 So I'm sure we'll be interested. Undoubtedly if you see a -- 20 something that is interesting to you, you would then be 21 proposing a full suite of logs to evaluate that, I assume. 22 MR. KNOCK: Yes, very much so. 23 CHAIRMAN JOHNSTON: Thank you. In terms of annular 24 disposal, I guess I have a question there. So who is the -- 25 our annular disposal person? · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · . . 67 1 MR. IRELAND: Doug. 2 CHAIRMAN JOHNSTON: Doug again. Possibly. 3 MR. IRELAND: We'll go to the other Doug. 4 CHAIRMAN JOHNSTON: Yeah, okay, Doug Chester. Maybe it 5 would also help to get that slide up on the screen as well. 6 MR. CHESTER: The geology slide? 7 CHAIRMAN JOHNSTON: Yes. 8 MR. CHESTER: Let's go this way. CHAIRMAN JOHNSTON: In terms of the ability of these 9 10 zones to receive fluids what can you tell us about that 11 relative to the possibility of the frac- you know, relative 12 to the fracture pressure around the shoe or at the shoe? 13 MR. CHESTER: The only data that we have to go on at · 14 this time is when we freeze-protected 1-22 last year. We had 15 flushed the annulus and displaced with diesel, and we did see · 16 the reservoir take -- excuse me, the reservoir, the injection 17 area or disposal interval took fluid at a pressure that was 18 less than the essentially leak-off test that we had tested 19 prior to that operation. 20 CHAIRMAN JOHNSTON: So you feel that these zones will 21 take fluids at a pressure less than the fracture pressure at 22 the shoe of the surface casing? 23 MR. CHESTER: I guess as you can see from this log, we 24 have put a 12 pound gradient line on this strength curve, and 25 assuming that we get leak-offs in this surface casing area that MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuÏJe 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 68 1 we expect the injection interval should take fluid at a 2 pressure less than the leak-off test. Our problem right now is 3 we don't have any other than one kind of data point that's -- 4 and so that would be my concern, to blanketly say that yes, it 5 would be. But the one data point indicates that that is true. 6 CHAIRMAN JOHNSTON: Do you have a contingency plan in 7 the event that these zones that you indicated for annular 8 disposal, what happens if those zones do not take fluid? 9 MR. CHESTER: We would be forced to put a Class 2 10 injection well at the location and not use that for cuttings in ( 11 lead (ph) disposal. 12 CHAIRMAN JOHNSTON: But you're currently proposing a 13 Class 1 anyway, right? 14 15 MR. CHESTER: That is correct. 16 the Class 1 to begin with? CHAIRMAN JOHNSTON: Why wouldn't you necessarily go to 17 MR. CHESTER: Our modeling shows that the Ivishak and 18 Sag is tight enough that we feel like putting cuttings and 19 fluids and muds, we would get into somewhat of a screen-out 20 scenario to where the well would plug up with solids and we 21 would lose that well. And so our contingency plan is to try to 22 keep that as a more of a clear fluid disposal well, and we 23 would need something else for mudding cuttings. 24 25 CHAIRMAN JOHNSTON: So if the annular disposal doesn't prove to be an option for you then you're pretty much going to MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . 69 1 have to drill a second well, Class 2 dedicated disposal well? 2 MR. CHESTER: Yes, that is correct. 3 CHAIRMAN JOHNSTON: Thank you. We have a couple of 4 questions here from the Department of Revenue, and it has to do 5 with recovery estimates under your proposed development scheme 6 and your current plan. 7 MR. IRELAND: Okay. 8 CHAIRMAN JOHNSTON: So whoever would be the most 9 appropriate person to answer those questions. 10 MR. IRELAND: I'll be happy to field those. CHAIRMAN JOHNSTON: Okay. Does your estimate of 35 to 11 12 40% ultimate recovery reflect the bare development or I guess 13 the base development plan or is that based on your proposed ~ 14 development plan? MR. IRELAND: That represents the base development . 15 16 plan. 17 18 CHAIRMAN JOHNSTON: And..... MR. IRELAND: Our publicly stated number for Alpine 19 reserves is 365 million barrels. 20 CHAIRMAN JOHNSTON: And then what is the estimate of 21 the higher ultimate recovery for the new proposed plan? 22 MR. IRELAND: I'd really prefer to wait to answer that 23 question till we've had time to do the proper technical 24 evaluation as well as economic evaluation. Obviously somewhat 25 higher is what we'd be hoping. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suue 1460 Anchorage, Alaska 99501 (907) 276-3876 . . 70 · 1 CHAIRMAN JOHNSTON: So sometime in the future you'd be 2 prepared to provide that estimate to the commission? 3 4 5 take? 6 MR. IRELAND: Yes. CHAIRMAN JOHNSTON: Any idea of how long that would MR. IRELAND: I'd go back, by next summer certainly we 7 hope to have that new plan in place and be ready to present. 8 CHAIRMAN JOHNSTON: Thank you. So based upon that 9 testimony it doesn't appear that you're in a position to really 10 talk knowledgeably about any of the relative contributions that 11 in-field drilling and miscible WAG injection may contribute to 12 ultimate recovery? 13 MR. IRELAND: No, I don't think it would be appropriate · 14 to comment on that at this time. 15 CHAIRMAN JOHNSTON: What is the estimate of well 16 productivity of the core area in barrels per day? 17 MR. IRELAND: We're hoping for those wells to produce 18 multiple thousands of barrels a day. I think the absolute 19 upper limit -- tubing limits for 4~" tubing would be something 20 on the order of 10,000 barrels a day. We're certainly not 21 expecting that for these wells. 22 CHAIRMAN JOHNSTON: And if you acquired that would -- 23 how long would you be able to sustain such production? Would 24 that be just a short time spike and then tipping off -- 25 tapering off to a sustained rate of what? · MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuiJe 1460 Anchorage, Alaska 99501 (907) 276-3876 . . . . . 71 1 MR. IRELAND: Yeah. Probably the initial rates would 2 falloff to -- or (indiscernible - coughing) of each other is 3 it would falloff to maybe half their initial rates sometime 4 over the course of a year. 5 CHAIRMAN JOHNSTON: And how would that compare to say 6 some of the rates in the peripheral areas that are not quite as 7 productive? 8 MR. IRELAND: If you just base off the core area being 9 limited by 600 millidarcy feet and the periphery down to 200 10 millidarcy feet, then maybe some kind of 2:1, 3:1 ratio on 11 average. But of course each well will have quite a bit more 12 variability than that. 13 CHAIRMAN JOHNSTON: Thank you. COMMISSIONER CHRISTENSON: I have one question. Do you 14 15 have a production profile for the rates of water, oil and gas 16 for the basis plan? 17 MR. IRELAND: We certainly have forecasts. I don't 18 know that we supplied that -- I don't know that we have that 19 with us anywhere. 20 COMMISSIONER CHRISTENSON: We'd like to have that if 21 you've got it together. Thanks. 22 CHAIRMAN JOHNSTON: Any further questions? Okay. It 23 looks like we've just made a request for additional data, so 24 I'd suspect we need to keep the hearing record open. It's also 25 my understanding that the Department of Natural Resources MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1460 Anchorage, Alaska 99501 (907) 276-3876 · · 14 15 16 17 18 19 20 21 22 23 24 25 · . . 72 1 wishes to put in written comments relative to the well testing 2 frequency, and so to allow the submittal of this additional 3 information, as well as the DNR comments, I'd like to keep the 4 hearing record open an additional two weeks. So two weeks from 5 today, whatever that may be for uS,we'll close the record in 6 this matter. 7 So is there any other individual wishing to make a 8 statement before we close for the day? With that, I'd like to 9 thank each and everyone for coming. It's always a pleasure to 10 see a group of Alaskans that are interested in gas development, 11 especially in this area of the world. Thank you for your 12 interest and we'll close the record in this matter two weeks 13 from today. Thank you. (Off record - 11:50 a.m.) END OF PROCEEDINGS MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, SuÌJe 1460 Anchorage, Alaska 99501 (907) 276-3876 · · · . . 1 C E R T I F I CAT E 2 UNITED STATES OF AMERICA) I )ss. 3. STATE OF ALASKA ) 4 I, Cari Ann Ketterling, Notary Public in and for the 5 State of Alaska, and Reporter for Metro Court Reporting, do 6 hereby certify: 7 That the foregoing Alaska Oil & Gas Conservation 8 Commission Hearing, was taken before Laura Ferro on the 3rd day 9 of December 1998, commencing at the hour of 9:00 o'clock a.m., 10 at the offices of Alaska oil & Gas Conservation commission, 11 3001 Porcupine Street, Anchorage, Alaska; 12 That the hearing was transcribed by Laurel L. Earl to 13 the best of her knowledge and ability. 14 IN WITNESS WHEREOF, I have hereto set my hand and 15 affixed my seal this 8th day of December 1998. 16 a 17 \. \. \. \C ({ {( ( ({I'I: \.\\ ~~ ~~~1'~~ ~ ~ tI.· ........ .."t-.-;:. ~~:~OTA~j.:.~ ~ (j: ....... . Q:::' 2: : ÞUBUC : :2 'S:i'..~ ...... ß'..ß,'~ --:::. ~.. r.."l1"~' ~__.y ..:;,. . . . Of þ..'~; . ,,'b' ,-V ~ . II . .. "'.' :/....i ~~~,tì\)\'\ '.I}})})}]))))\ 18 19 2°1 21 22 231 I 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suùe 1460 Anchorage, Alaska 99501 (907) 276-3876 #5 . . ALASKA OIL AND GAS CONSERVATION COMMISSION NAME - AFFILIATION (pLEASE PRINT) December 3, 1998 9:00 AM Alpine Pool Rules TELEPHONE Y'\\C~(~ \) il,\..j\~ A-<-Lv 2(00:; -¡'-tï 8 . I . j( C~ f -(. fiB. ~, - r/7 q '7 )')Ö\.l\."F/'JI.J ¡",f'J e-? -:2 V 3 ~7 / "" ~,/ !loJ):¡ w Zu-- I ~sy r-TCJ.IA RfclActv,is.-A-AJ 203- 44-ró4 \(Ivt~.s herwöd~ M¡v\S ~ 7/ - 60 '65 p-o)¡ 11\(.\;1(' d c.o ù:t:>f": (2 <... ~¡ 4 (þ 4 Lt b0 f 0 .¿ û-S- J..C.{' -(( 0 ( ?-~3- 4707 '3~ ~- ~t;?ò .:2b5' ~bY6'Ç 2., '71 -(,0 '7 r ,;z G 7- 1£/ ¿/ q 2 lS--- & 1.5~. .51 r 5'/ ¿) l{ or: < N1 a -:r='(. vJ lirleh ç hf. )) e (). v., (;:V1 ~ l'~.' AÞ..w l< 'ye tu C olvt ev ~rf f!,c,~,r . ~~ hôcÁ 53", + C ~",,~¿'<2fS GCvv",\ Gv 5~~-\-S o'\-...... ./ I "to" _', L' 'II /1- A I /.~IÍJ/ -'/1'.>71".. i. //(1.," / J)f::-n- 7 S It1.-GL 7. ~ V 'br<Z:J Is.-d",,( II /1</,(> &.p5r~1) "-\'A<e ~..Icowc;~: '7C'L( p4l (e--- . K\"\st 0n .N e l SðY1 -.:r~. (¿ !-{~t::t- /J/I./I< £ 6/£.(.. , X~.uT sk#.., ¥0r~¿# 7~oý;'YfJ.. I f1 11\ :J\J \,e., \1\)v\e.. Q~,'/c ~()~ðl - ¡:1m J .....J,)~V\ Dú ¡ú I - 5b4-S30f- , 5"h9'.. -J5~5 Q y- tJD$ 3J 3 ...., ~- q 2. 8 7 3LfS- ~6 '3 '+ G 02109- 8f3/~ q..y - 50S ~ ~ 43- ''3 <0 dt d- ,'17- (L -:Sz- ;?'6.J-ÝZJY ;25>¿¡ - 0 f.. S? $-' ,773-- /2 3ð '2Çð1- 031 ¿ ~6~ ~11.s '1..71 - 65;5'7 )&'1- S-¡'Ui Do you plan to testify Yes No 'i-€4 ~P..r ¡J-:> t-t?s NO \'\.0 !\/ð' 1.£-$ ¿............. ./ c..--- ~ c-.... ,/ V \,.../'" ~ v t..--- ~ V t00 ¿.,-- ~. /V"6 .......-- "vb ~ ~. .-f o #4 .' . December 3, 1998 Mr. D.W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Alpine Pool Rules Dear Chairman Johnston: ARCO Alaska, Inc. (ARCO), as an owner and the operator of the Colville River Unit, requests that the Alaska Oil and Gas Conservation Commission issue rules for the Alpine Oil Pool as authorized by 20 AAC 25.520. An order at this time will enhance Commission understanding of proposed drilling activities, which are beginning over a year in advance of start-up. The purpose oftoday's hearing is to present testimony in accordance with 20 AAC 25.540. The public notice period started on October 16th, 1998. ARCO proposes to continue development drilling by operating under Title 20, Chapter 25 regulations; however, clarification and some exceptions are requested to those general regulations. A few of the more important issues to address include: · well spacing, · drilling and completion practices, · reservoir surveillance, · and injection plans. Attached are six copies of the application package, which includes the proposed rules, supporting testimony, and exhibits. Additionally, ARCO Alaska, Inc. (ARCO), as an owner and the operator of the Colville River Unit, requests that the Alaska Oil and Gas Conservation Commission authorize injection of RCRA exempt drilling and production wastes into strata within the unit boundary. The original Application for Disposal Injection Order was received in the Commission offices November 2, 1998. The public comment period started on November 3, 1998. The purpose of to day's hearing is to present testimony in accordance with 20 AAC 25.540. For additional information supporting either application, please contact Mike Erwin at 265-1478. Sincerely, ~~ RECEIVED r: EC ,,) 1998 OR\G\NAL \J Mark Ireland Aiaska o¡¡ & Gas Cons. Commission Anchora[]0 . . 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 Inun, 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 Alpine File e . Alpine Pool Rules ARca Alaska, Ine Anadarko Petroleum Corporation Union Texas Petroleum, LLC December 3,1998 - e Table of Contents Page I. Introduction 3 II. Geology 4 III. Reservoir 7 IV. Reservoir Development 8 V. Drilling 10 VI. Well Operations 16 VII. Facilities 19 VIII. Summary of Testimony 23 IX. Proposed Alpine Pool Rules 24 Exhibits 27 2 e e I. Introduction This hearing has been scheduled in accordance with 20 AAC 25.540 with a public notice period started on October 16th, 1998. The purpose of this hearing is to present testimony supporting classification of the Alpine oil accumulation as an oil pool and establish pool rules for development of said oil pool pursuant to 20 AAC 25.520. Additionally, we are prepared to present testimony supporting our Application for Disposal Injection Order in accordance with 20 AAC 25.540. The public notice period started on November 3, 1998. ARCO Alaska, Inc is presenting testimony today as Operator, on behalf of the Working Interest Owners (WIOs) of the Alpine oil accumulation. The scope of this testimony includes a discussion of geological and reservoir properties, as they are currently understood, and ARCO's plans for reservoir development and surveillance, well construction, facilities installation and project scheduling. This testimony will enable the Commission to establish rules that will allow economical development of resources within the Alpine Oil Pool. Development drilling is scheduled to commence during the first quarter of 1999 with production beginning June 2000. The Alpine Plan of Development will be delivered in accordance with 20 AAC 25.517, and will be released to the AOGCC and other stakeholders prior to field start-up. The properties to be developed (i.e., the Alpine Oil Pool) are leased from the State of Alaska and the Arctic Slope Regional Corporation. The Working Interest Owners are ARCO Alaska, Inc, Anadarko Petroleum Corporation and Union Texas Alaska, LLC. The Alpine Oil Pool is located within the present boundaries of the Colville River Unit. The Alpine Oil Pool WIOs have cross-aligned their interests throughout the Alpine Oil Pool. ARCO, on behalf of the Alpine Oil Pool WIOs, will file an application requesting the Department of Natural Resources to approve an Alpine Participating Area, which will include the Alpine Oil Pool. Said application will also include plans of development and operations for the Alpine Participating Area, including the Alpine Oil Pool. ARCO will file a copy of the Alpine Participating Area application with the Alaska Oil and Gas Commission. 3 e e II. Geology Introduction This section provides geologic data and interpretation in support of ARCO's proposed Alpine Oil Pool. Additionally, a review of the shallow zones proposed for annular injection of drilling fluids will be presented. 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. Stratierauhv 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 3). 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 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. Thin discontinuous sands with overall poor reservoir quality (see Exhibit 3) characterize the Lower Cretaceous Kuparuk Sandstone in the Colville River Unit area. The Fiord 1, approximately 2 miles north of the Alpine Oil Pool, penetrated 20 feet of Kuparuk net pay and tested ±1000 BOPD of 31.60 API gravity oil. Clastics in the Albian Torok Formation include thin-bedded turbidite sandstones with generally poor reservoir quality (Exhibit 3). Interbedded sandstone and mudstone packages up to 100 feet thick are complexly distributed across the Colville River Unit area. Åee of Sediments Based on ARCO in-house palynology and micropalentology the Alpine interval is 4 e . 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 4) 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. 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 of the Kingak and Miluveach formations. Hydrocarbon distribution is controlled by the distribution of reservoir quality sandstones. No water or gas cap has been encountered 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 north- northwest trending, down to the west, normal faults. At the Alpine level, most of the faults have small throws, generally less than 25 feet. Annular Injection Geology The geologic subdivisions associated with Colville River Field annular injection are shown on the Bergschrund 1 type log (Exhibit 6). Bergschrund 1 is approximately 4000 feet from the Colville Delta 1 pad (CD-I). The Sagvanirktok Group, and the West Sak, Schrader Bluff and Seabee Formations are easily correlatable across the Colville River Unit area. Lower Barrier Marine shales and claystones of the Lower Cretaceous Torok Formation comprise the barrier below the annular disposal interval. The lower barrier is at least 700 feet thick before grading downward into several packages of thin-bedded sandstones within the middle and lower Torok Formation. Annular Disposal Interval Interbedded shallow marine sandstone and shale of the Upper Cretaceous Seabee Formation and uppermost Torok Formation characterize the annular disposal interval. The total interval is approximately 1800 feet thick. The sandstones are very fine to fine- 5 e e grained and range from unconsolidated to mostly consolidated. The sandstones and mudstones are correlatable at distances over 2 miles. Upper Barrier The upper barrier is composed of 1,000 feet of marine to nearshore shales and siltstones of the Upper Cretaceous Schrader Bluff Formation. The shales contain common volcanic ash interbeds. The siltstones contain thin coal interbeds. Lithology above the Upper Barrier The Upper Cretaceous West Sak Sandstone overlies the upper barrier. It is composed of 300 feet of interbedded sand and claystone. Overlying the West Sak sands are sands and gravels within the Tertiary Sagavanirktok Group. Most if not all of the Sagavanirktok Group is within continuous permafrost. The permafrost ranges from 800-950 thick in the Colville River Unit area. 6 e e III. Reservoir Introduction This section will summarize reservoir properties. Core data provides the foundation for much of the rock property information presented in this section. Whole cores were collected from the Alpine #1, Neve #1, and Nuiqsut #1 wells. In addition rotary sidewall cores were obtained from the Alpine #1, Alpine #3, Bergschrund #1, Bergschrund #2A, and Fiord #3. A laboratory fluid study performed on subsurface oil samples, obtained while flow testing the Bergschrund #1 and Alpine #1B wells, provide the basis for the reservoir fluid description. Porosity. Permeability and Water Saturation The Alpine sandstone is very fine-grained with core measured porosity ranging from 15- 23% and averaging 19%. It has air permeability ranging from 1 md to 160 md, averaging 15 md. The average core based water saturation (after correcting for invasion) was measured at 20%. Net Pay Determination A porosity cutoff of 15% and a water saturation cutoff of 50% define net pay. Reservoir Fluids and PVT Properties The initial reservoir pressure of the Alpine sandstone is 3175 psig at 6864' true vertical depth subsea (TVDSS). For future reference, this equates to 3215 psig at 7000' TVDSS. Average reservoir temperature is 160 degrees F. Well test pressures, RFf pressures, and oil sample fingerprinting indicate the Alpine accumulation is in continuous hydraulic communication. Bottomhole reservoir fluid samples were taken in Bergschrund #1 and Alpine #IB. Analyses of these samples indicate the reservoir is undersaturated with a bubble point pressure of 2454 psig. At initial reservoir pressure, the formation volume factor is 1.469 RB/STB based on constant composition expansion experiments. Solution GaR under these conditions is 850 SCF/STB. Reservoir fluid density at the bubble point pressure is 0.6786 gmlcc. Oil viscosity is 0.46 cp at reservoir conditions. Oil gravity, as determined during the actual testing, is 40 degrees API. Orhdnal Oil-in-Place (OOIP) The stock tank OOIP volumetric estimates for the Alpine Oil Pool range from 900 to 1100 MMSTB, with an expected value of about 1000 MMSTB. Net pay maps were developed from 3-D seismic and well control data. Water saturation and porosity maps are based on interpolation of well properties. 7 e e IV. Reservoir Development Introduction This portion of the testimony includes a discussion of the recovery process selection, reservoir mechanisms, development strategies, and future optimization plans for the Alpine Oil Pool. Recoverv Process Selection To evaluate the performance of the Alpine reservoir, a 3-D compositional model was constructed covering the entire Alpine Oil Pool. Lean gas injection, miscible gas injection and waterflood development scenarios were evaluated with this model. Waterflooding with seawater was the recovery method selected. Additionally, waterflooding could be followed later with either lean gas or miscible gas injection to further improve ultimate recovery. The major uncertainty in the waterflood case is the ability to inject water at acceptable rates. In the event water injectivity is below expectations Alpine could be converted from a waterflood to gas flood. Recoverv Mechanism Fine grid models were run to develop a "truth case" for calibrating the full field models. The base case assumed primary recovery from an undersaturated oil reservoir. This model showed that the waterflood recovery process had excellent volumetric sweep efficiency and more than insignificant additional recovery over primary. The low degree of permeability variation, the favorable water to oil mobility ratio of 0.10 and the relatively thin reservoir section with no identifiable continuous permeability barriers all contribute to high volumetric sweep efficiency. Current Development Approach The scope of the current Alpine development project is broken into two Phases. Phase 1 provides for 50 new wells (this includes the two existing wells drilled in 1998) and Phase 2 provides for an additional 42 wells with a total of 92 wells. Total development includes 32 horizontal wells and 60 vertical wells. Horizontal wells are on 275-acre spacing and vertical wells are on 160-acre spacing. Wells are drilled out to a 200 md-ft cutoff, which is assumed to be the economic limit for Alpine wells. Potential Revised Development Plans The Alpine Owners are evaluating a revised development plan, changing the recovery process and tightening the well spacing. The current recovery process is waterflood in the center of the field and gas re-injection around the periphery. The revised development plan includes miscible-water-altemating-gas (MW AG) throughout the field. Gas will be enriched to become miscible with the reservoir oil. The currently planned well spacing is 275 acres in the center and 160 acres around the periphery. The revised well spacing would include horizontal wells on 135 acre spacing throughout the field, in order to take 8 e e full advantage of the MW AG process. The revised development plan calls for up to 140 wells. Future Optimization Optimizing field development will be an ongoing process requmng additional data, laboratory studies and reservoir modeling. Current studies are focused on updating the full field model with a new reservoir description, new relative penneability infonnation, and a new equation of state characterization. The effective length and skin of the model wells is being tuned based on well test data. Simulation studies to determine the incremental recovery from MW AG are also underway. We have plans to test extended length horizontal wells and multilateral wells to reduce the number of wells. Producine Gas-Oil-Ratio Expectations. Because the Alpine facilities will be re-injecting produced gas into the Pool, the GaR is expected to rise above solution GOR in some wells. The breakthrough of re-injected gas will cause gas-oil ratios of some producing wells to exceed limits set forth in 20 AAC 25.240(b). Additionally, the Alpine Oil Pool average reservoir pressure will be maintained above the bubble point pressure with seawater injection for pressure maintenance. This additional recovery project will be further developed in the upcoming Area Injection Order hearing. For these reasons we request exemption from this rule. Well Conversion Strate2V Alpine development is designed to provide a 1: 1 injector/producer ratio. At startup of the production facilities, we expect to have a limited number of producers available. To briefly increase production at a time when the water supply line from Kuparuk is not expected to be available, pre-production of injection wells may be appropriate. After a short pre-production period, these pre-produced injectors would be placed in injection servIce. 9 e e v. Drilling Introduction This portion of testimony will include a description of our logging, drilling, casing, cementing, well suspension, annular injection and blow-out prevention equipment (BOPE) testing plans. Drillin2IW ell Desien The Alpine Oil Pool will be accessed from wells directionally drilled from one of two gravel pads utilizing drilling procedures, well designs, and casing and cementing programs consistent with current practices in other North Slope fields. Alpine will be developed utilizing the latest in directional drilling and extended reach techniques. The following paragraphs 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. 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 utilizing the latest directional techniques from surface casing, encountering the top of the Alpine at 50-70 degree inclination. Production casing will be set close to horizontal and cemented within the Alpine sands. 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 to a predetermined equivalent mud weight (EMW) above reservoir pressure. Note that the Alpine reservoir fracture gradient (20 AAC 25.030(d)(2)(D)) will not be reached to minimize formation damage. Production hole will be drilled beyond the casing shoe horizontally in Alpine sand. Lengths achieved will vary from 500' up to perhaps 8,000 ft. depending on 10 e e 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. Un cemented slotted liners are included in the drilling plans on an "as-needed" basis. For example, well bores 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 500 feet measured depth or more above the Alpine. An example would be any extended reach S-shaped wells that encounter Alpine sands at inclinations below 60 degrees. These wells would follow the cementing and testing conventions above. In addition to conventional open hole and perforated completions, it is proposed that pool rules authorize the following alternative completion methods a) Slotted liners, wire-wrapped screen liners, or combinations thereof, landed inside of cased hole and which may then be gravel packed. b) Vertical or "conventional" open hole completions. Openhole completions may subsequently be completed with slotted or perforated liners, wire-wrapped screen liners, or combinations thereof, and may be gravel packed. c) Horizontal or "high angle" completions with liners, slotted or perforated liners, wire-wrapped screens, or combination thereof, landed inside the horizontal extension, and which may be cemented and perforated or gravel packed. d) Multi-lateral type completions in which more than one wellbore penetration is completed in a single well, with production gathered and routed back to a central wellbore. If the Operator desires to utilize any other casing or completion methods other than those presented above it shall seek administrative approval by submitting and presenting data demonstrating that such alternatives are based on sound engineering principles. Batch Drilline: Plans To expedite the drilling process and minimize pad storage requirements the drilling schedule will follow a "batch drilling" schedule. For example, 5 wells may be drilled to surface casing point and suspended while the rig moves to the next well. Before the end of the drilling season, each of the 5 wells will be drilled to completion. This process will be described in the initial Application for Permit to Drill, Form 10-401. The following details a typical batch drilling suspension procedure. a) Wells suspended after setting surface casing will be left as follows; 1) Surface casing shoes will not be drilled out. 2) Cement plugs will be left inside the surface casing a minimum of 50 feet above the shoe. 3) Wellbores will be displaced to water and freeze protected. 11 e e 4) Wellbores will be pressure tested to verify integrity of the cement plug and casing. Notice of the test will be given to the Commission in time such that a representative of the Commission may be present to witness the work. 5) Wellheads will be capped with a dry hole valve. b) Wells suspended after setting production casing will be left as follows; 1) Production casing shoes will not be drilled out. 2) Cement plugs will be left inside the production casing a minimum of 50 feet above the shoe. 3) Wellbores and annuli will be displaced to water and freeze protected. 4) Wellbores will be pressure tested to verify integrity of the cement plug and casing. Notice of the test will be given to the Commission in time such that a representative of the Commission may be present to witness the work. 5) Wellheads will be capped with a dry hole valve. The AOGCC will be notified of rig moves. Changes to the approved drilling permit will be communicated to the AOGCC on Form 10-403 in accordance with 20 AAC 25.015. Ice roads currently provide the only available means for rig travel between the pads or other fields. With pad to pad moves limited to the winter season, the potential exists for rig moves which strand a previously "batch drilled well" on a pad more than 12 months before it can be drilled to completion. In this event, an Application for Sundry Approvals, Form 10-403 will be filed with the Commission in accordance with 20 AAC 25.015. Blowout Prevention It is proposed that the rule for blowout prevention in the Alpine Oil Pool be written according to the provisions established at 20 AAC 25.035 (Secondary Well Control: Blowout Prevention Equipment (BOPE) Requirements) of the AOGCC regulations with one exception to 20 AAC 25.035(a)(7)(a). Operator proposes that BOPE and annular preventer tests shall be made when the BOPE is installed or changed, and at least once every two (2) weeks after that. This is consistent with the recent revision to the U.S. Department of Interior Mineral Management Service (MMS) regulations concerning BOPE testing on OCS operations. See 63 FR 29604-608, June 1, 1998. Test results will be recorded as part of the daily record in accordance with 20 AAC 25.070(a)(1). Except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance with API Recommended Practice 53 for blowout prevention systems. Directional Drillinl!: Continuous MWD surveys will be used as they have proven to be effective in surveying horizontal wells on the North Slope. 12 e e The detailed reporting and plotting for directionally drilled wells as described in 20 AAC 25.050(b) should be waived for the Alpine Oil Pool. Current guidelines call for extensive data packages in the Application for Permit to Drill on all wells located within 200 feet of a directionally drilled well. All drilling will be confined within Unit and Pool boundaries with previously established working and royalty ownership. Instead, the Operator proposes to include the following in each Application for Permit to Drill; 1) plan view, 2) vertical section, 3) close approach data, 4) and directional data. Loe:e:ine: Operations Facies interpretation will be the most critical data requirement and the log suite planned in the Alpine reservoir includes resistivity and gamma ray logs across the productive intervals. These logs will be obtained from MWDIL WD tools positioned in the drilling BRA. At this time neither log provides facies interpretation. Neutron porosity logs in the two previous horizontal wells were ineffective in facies determination due to reservoir homogeneity. Without log identification of formation facies, ROP and cuttings become the critical reservoir quality determinants. At some point in the future, it is possible that Alpine wells could be drilled solely using rate of penetration (ROP) as well as other drilling indicators to locate the pay zones. In keeping with Commission practice, at least one (1) well on each drilling pad will be logged from conductor casing to TD with GR/Resistivity/Neutron tools. As the first well on pad, CDl-22 was successfully investigated with a suite of gamma ray/resistivity/ neutron/density logs. However, this did not occur while drilling CD2-35 due to wellbore conditions. The next CD-2 well drilled will be logged with gamma ray/resistivity/ neutron/ density tools from the conductor casing to the Alpine Oil Pool. Additional log investigation of formations from the surface casing shoe to the Alpine Oil Pool will be performed at Operator discretion. Drilline: Fluids The drilling fluid program designed for Alpine wells will be prepared and implemented in full compliance with 20 AAC 25.033 in the AOGCC regulations. Formation pressures for the strata to be penetrated are well known and documented based on numerous Colville Delta wells, which have already been drilled through the Alpine Oil Pool. Wellhead and Production Tree Desie:n The Alpine wellheads and trees are designed for the operating conditions expected at Alpine. The "horizontal wellheads" are very similar to those currently being used in the West Sak Oil Pool. Horizontal trees route oil and gas flow through a port in the side of the tubing hanger, and then through a wing valve to the production flow line. This design reduces the height of the wellhead and allows the well to be worked over without removing the flow line. 13 e e All wellhead and production tree equipment carries the API monogram and meets or exceeds API RP 14C. Annular Disposal of Drilline: Wastes Annular disposal of drilling waste is proposed during Alpine drilling and completion operations. It is requested that permission be granted for injecting drilling fluids into various strata as shown on Exhibit 6 and described in Section 2 (Geology) per 20 AAC 25.080. Each well designed for annular injection will be identified as such on the Application for Permit to Drill, 10-401. Upon completion of a successful formation integrity test (FIT), a 10-403 will be submitted for Commission approval prior to commencing injection. There are no underground sources of drinking water (USDW' s) in the area, or potablelindustrial water wells within one (1) mile of the Alpine Oil Pool. Formation markers are shown in Exhibit 6. The only publicly recorded wells within 1/4 mile of disposal operations will be other Alpine Oil Pool wells. Incidental fluids from drilling operations will be pumped down the annulus of wells in the Alpine Oil Pool. Disposal will take place in wells on the same pad as the waste generating operation. Please note that cement rinseate is proposed for injection down an open annulus. The surface/production casing annulus will be left with a non-freezing fluid during extended idle periods. When isolation is required in accordance with regulations concerning standoff from significant hydrocarbons, and the surface shoe is within 200' TVDSS of the top of the hydrocarbons, the annulus will be sealed with cement from the surface shoe to the base of the permafrost with pack fluid or diesel. If the hydrocarbons are well below the shoe, then sufficient cement volume will be pumped to cover the formation. Surface casing will be set at approximately 2350' TVDSS near the Cretaceous C-30 marker (Exhibit 6). The annular disposal interval consists of 250' -300' of unconsolidated sandstone and mudstone. Approximately 1100' of barrier mudstone and siltstone separates the receiving interval from the overlying West Sak sands. The maximum volume of fluids pumped down the annulus of any well will not exceed 35,000 barrels without AOGCC permission. Fluid densities will range from 6.8 ppg for diesel to a maximum of 12.0 ppg for drilling mud and cuttings. Using 12 ppg fluid and a maximum pumping pressure of 1500 psig, the maximum pressure at the surface casing shoe is estimated by; Maximum Shoe Pressure = 12.0 ppg x 0.052 psi/ft x Surface Casing Shoe Depth + 1514.7 psia Maximum Shoe Pressure = 2981 psia (assuming Surface Casing Shoe Depth is 2350' TVDSS) The surface and production casing strings exposed to the annular pumping operations are determined to have sufficient strength by using 85% collapse and burst ratings as listed below. OD (in.) 9-5/8 7 Weight (lb/ft) 36 26 Grade Range Connection J-55 3 BTC L-80 3 BTC- Mod Collapse (psia) 2020 5410 Collapse x 85% 1717 4599 Burst (psia) 3520 7240 Burst x 85% 2992 6154 14 e e Based on formation strength analysis the expected surface pressure to inject fluid would be 284 psig for a 12 ppg fluid. The minimum in situ horizontal stress is approximately 1750 psig. Surface injection pressure = 1750 psig - (12.0 ppg x 0.052 psi/ft x 2350' TVDSS) = 284 psig Fluids to be disposed of in a surface casing annulus will be limited to drilling fluids and wastes associated with drilling wells as defined in 20 AAC 25.080(h). It is requested that cement rinseate be determined as drilling waste under 20 AAC 25.080(h)(3). 15 e e VI. Well Operations Well Desi2n and Completions Typical completions will utilize 3-112 and 4-112" tubing to exploit the production potential of horizontal wells. The smaller tubing may be appropriate in the peripheral extensions of the field. Either design will be consistent with previous designs in use across the North Slope, utilizing 9-5/8"surface casing, 7" production casing, and 4-112" or 3-112" tubing. All producing wells will be equipped with gas lift mandrels. A single packer will provide pressure isolation for the tubing-casing annulus. Wells with liners placed in the horizontal segments will utilize combination liner hanger/packers. In this case, the tubing string will utilize sliding seals which seal into a polished bore in the liner hanger/packer. All completions will target reserves in the Alpine Oil Pool. Wellbore departure will reach laterally as far as 15,000 ft. from the current pad locations. High departure and extended horizontal completions will push measured depths to the 21,000-ft. range. Artificial Lift Gas lift will be employed at Alpine as the sole artificial lift mechanism to optimize reservoir pressure drawdown, provide lift for long reach horizontal wells, and enhance production rates at the increased watercuts anticipated following waterflood response. Sidetracks Openhole completions provide an ideal platform for future sidetracks. Pressure communication and waterflood breakthrough will delineate directional permeability, channels or thief intervals. Once identified, openhole completions can be plugged back and redrilled to improve sweep and enhance recovery. At this time we anticipate sidetracks which preserve overall line drive patterns with parallel laterals. In addition to pattern conformance, sidetracks could increase water injection, sidestep faulting or penetrate bypassed oil. Sidetracks within the Alpine Oil Pool can be expected to expose producing reservoir pay within 500' of established well bores in the Alpine Oil Pool. Initial spacing between horizontal wells along the proposed line drive will be approximately 1,000 feet from one well's toe to the second well's heel, and 1,500 feet laterally between rows. Alpine sidetracks will focus on enhancing two dimensional reserve recovery (x & y) since the reservoir is thin enough that any vertical sweep (z) is not considered problematic. Sidetracking scenarios can be expected to target maturing reservoir sections for increased injectivity, reach undrained or fault isolated pockets, avoid conductive faults, and improve enhanced recovery techniques. As such, sidetracks can be expected to radiate out laterally from the trunk well, aligning generally parallel the trunk well in the form of laterals. Each lateral cannot extend more than 100-500' from the trunk wellbore or the 1,500 feet spacing between rows quickly breaks down. For this reason the Alpine Oil 16 e e Pool is requesting a waiver on spacing limitations, with the exception of a 500-foot perimeter around the pool. Reservoir Surveillance Pressure monitoring is a key component of the long term Alpine Oil Pool surveillance. Static bottomhole pressure surveys will be conducted in all new additional recovery (injection) wells prior to initiating injection. Static surveys will similarly be performed in certain production wells. For annual pressure surveillance, a minimum of six (6) pressure surveys will be conducted annually in the field, concentrating on injection wells. Since lengthy horizontal wells require extended shut-in periods, often months long, to achieve stabilized bottomhole pressures alternative pressure survey methods will be required. Alternative allowable survey techniques include open hole wireline RFf measurements, cased hole pressure buildups with bottomhole pressure measurement, injector surface pressure fall- off, static pressure surveys following extended shut-in periods, or bottom hole pressures calculated from well head pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressure build-up tests will be extrapolated to estimate static reservoir pressure while injection wells may become the preferred source for static pressure surveys. All pressure surveys will be reported annually, rather than monthly, to reduce paperwork due to the limited number of surveys. While the pool extends between 6,800 TVDSS and 7,700 TVDSS, a representative common datum for reporting should be 7,000 feet TVDSS. The 7,000 TVDSS datum runs through roughly the center of the pool as seen in Exhibit 5. Additional surveillance logging will include spinner surveys to monitor effective producing or injecting well length. This will be accomplished with coil tubing conveyed memory logging tools. Spinner logging will provide information concerning effective producing length in the horizontal sections often leading to stimulation and remedial well work, as well as identify conformance and sweep patterns. At this point in time, none of the conventional base logs (resistivity, density, gamma ray or porosity logs) have been able to differentiate inter-Alpine facies, and therefore pay quality. Until more effective logging tools or correlations are identified, surveillance logging may be limited to spinners and temperature tools. Overall, waterflood surveillance will focus on understanding fluid migration patterns, identification of unswept target intervals and lenses and permeability trends that differentiate swept from un swept reservoir intervals. Well work Operations Well work operations in the Alpine Oil Pool will include routine mechanical integrity tests of each wellbore and artificial lift maintenance. Unlike more typical multi-zone or multi-layer fields on the North Slope, the Alpine Oil Pool represents a single hydrocarbon accumulation. Production from a single pool with openhole completions minimizes profile modifications, perforating and plugback operations. With a remote location and limited heavy equipment access, major work activities including fracture or acid stimulation and tubing or casing repairs will be performed during winter utilizing ice road 17 e e access. For ongoing wellwork we are requesting a waiver to the requirements of 20 AAC 25.280(a) for the following operations on producing wells and enhanced recovery wells; a) perforate or reperforate casing, b) stimulate, c) and coil tubing operations with the exception of drilling or sidetracks. This is intended to reduce the paperwork burden on both the AOGCC and the Alpine Oil Pool Operator. Summary reports and records will continue to be kept in accordance with 20 AAC 25.280(c,d). Stimulation Methods Stimulation techniques may be used at some point to enhance productivity of the Alpine reservoir. Stimulation to remove drilling induced fonnation damage and enhance near weBbore flow characteristics will be perfonned to Íncrease the commercial flow rates in this reservoir. Propped hydraulic fractures appear to be the most promising stimulation technique available at present. WeBbore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Subsurface Safety Valves Consistent with the intent of statewide AOGCC regulations (20 AAC 25.265) for onshore fields in environmentaBy sensitive areas, sub-surface safety valves (SSSVs) will be instaBed in all new wells in the Alpine Oil Pool. Producing weBs will receive a surface controBed automatic SSSV instaBed below the pennafrost at approximately 1,000' TVDSS. Injection weBs will be equipped with a single tubing profile nipple set below the pennafrost at approximately 1,000 ft. for instaBation of a slickline conveyed automatic fail-closed injection valve (check valve that is not surface controBed). Consistent with the Prudhoe Bay and Kuparuk Pools, the Alpine owners request that in the future Operator discretion prevail in the removal of SSSVs. SpecificaBy, the Operator requests the option to remove SSSV's for weBs producing less than 1,500 BOPD and 5,000 MSCFD. This provision will provide relief to the Operator and regulatory agencies for declining producers, particularly those dependent on artificial lift. Periodic inspections and testing, not to exceed annuaBy, will be conducted foBowing notification of the Commission. Surface Safety Valves AB wells capable of unassisted flow of hydrocarbons will be equipped with fail-safe automatic surface safety valves (SSVs). They have been specificaBy designed to accommodate the weBhead and casing requirements of Alpine weBs, and will be located in the typical "wing" position. These devices will be pressure actuated and are designed to isolate well fluids upstream of the SSV whenever pressure limits are exceeded. Additionally, injection well flowlines will be equipped with check valves in the surface pIpmg. Periodic inspections and testing, not to exceed semi-annually, will be conducted following notification of the Commission. 18 e e VII. Facilities Introduction The Alpine Oil Pool is located approximately 40 miles west of the Kuparuk base camp and is a completely independent operation. The pool is being developed with two main gravel pads connected by a 3-mile long road. The first mile of the road also serves as a runway for air support of the operation. The eastern pad is roughly 2600 feet long and varies in width from 400 to 750 feet. This pad has several discreet parts. The central processing facility (CPF) is located on this pad as well as the field infrastructure including the camp, shops, and warehouse. At the western end of this main pad is the first drill site (CD-I) designed for 40 wells and a large storage pad for storing drilling supplies. Three miles to the west is the second drill site (CD-2). This pad is 500 feet by 800 feet and is designed for 50-60 wells. It also includes a smaller section for storing drilling material. The road connecting the two pads is designed to allow the rig to move back and forth between the pads throughout most of the year. The Colville River Field does not have a year round road connecting to the existing North Slope infrastructure. Ice roads will be built in the winter to bring in supplies. During the 8-9 months per year when ice roads cannot be utilized, the Colville River Field will be dependent on air support for all supplies. Infrastructure Alpine is being built as a stand-alone grass roots installation. Therefore the entire infrastructure required for operating and maintaining an oil field on the North Slope of Alaska is included in the design. Primary features include: 1. A 140 bed permanent camp with kitchen, dining room, recreation facilities. 2. All utilities required for running the camp including potable water treating, waste water treating, solids incineration, and composting for food wastes. 3. Small warehouse for onsite storage of critical materials. 4. Shops for production and drilling. 5. Wash bay for cleaning all equipment and properly handling all wash water effluent. 6. Fine Water Mist system for fire protection of the infrastructure and the process plant. 7. Telecommunications equipment required for all phones, radios, and computer connections within the field and back to Anchorage. 8. 5,000-ft runway for handling aircraft up to and including C-130 Hercules aircraft. 9. Class-I waste disposal well. 19 e e Drill Site Facilities The CD-l drill site is adjacent to the processing plant. This drill site is designed for 40 wells equally split between producers and injectors. Wells are individually piped into manifold buildings were the production fluids are commingled for transport through a short pipeline into the processing plant. A separate test header is connected to each well slot so that produced fluids can be individually routed through a test separator in the main plant. This test separator will provide two-phase separation and measure flow rates of the gas and liquid phases. The liquid stream will pass through a Phase Dynamics meter to determine the oil/water split of the liquid. The manifold building will also have water and gas injection headers bringing high- pressure fluids from the plant to the drill site for injection. Each injection well will be piped to receive either water or gas depending on the reservoir development plan. CD-2 is located approximately 3 miles west of the CD-l pad. This pad is designed to have 50-60 wells equally split between producers and injectors. The manifold facilities are identical to those on CD-l with production being commingled into a 3-mile long 20" pipeline back to the processing plant. The multi-phase test meter for CD-2 production CD-2 is located on the drillsite. This two-phase separator and meter measures oil, gas, and water composition of the well fluid by the same means as the separator for CD-I. Central Processini! Facility The Central Processing Facility (CPF) takes the well production and separates fluids into oil, gas, and water streams. Oil is sold through a sales meter skid and pumped through a 14" pipeline to Kuparuk's CPF-2 where it connects into the existing Kuparuk pipeline system. Gas is dehydrated and compressed for reinjection into the Alpine reservoir with a small portion of the gas used as fuel for the facility or gas supply to Nuiqsut. The separation train consists of three primary process vessels, including the Inlet Separator, Low Pressure Separator, and Dehydrator. These three vessels remove gas and water from the oil to produce pipeline quality crude oil. This section of the plant contains heat exchangers to enhance water separation and control sales oil vapor pressure, heat exchangers to cool sales oil, and pumps for transferring sales oil from Alpine to Kuparuk. A sales meter skid, with a ball type meter prover conforming to API Manual of Petroleum Measurement Standards, measures the oil sales volume pumped into the pipeline. The oil section of the plant and pipeline are designed for a nominal rate of 90,000 BOPD. Gas separated from oil in the separation train is processed and compressed for reinjection into the reservoir. There are two compression systems in the Alpine CPF. The low- pressure compressor is an electric driven centrifugal compressor, boosting gas in the plant up to 150 psig. The injection compressor is a three stage centrifugal compressor driven by a GE Frame 5 gas turbine. The compression train boosts inlet gas from 150 psig to 4500 psig for reinjection into the reservoir and for use as artificial lift gas on the production wells. Between the first and second stages of this compressor is a dehydration system for removing water from the gas. The dehydration system uses Triethylene Glycol (TEG) and is similar in design to other North Slope dehydration systems. Approximately 20 e e 15-18 MMSCFD of dry fuel gas is then available to both Alpine and the neighboring vìl1age of Nuiqsut. With WIO approval for a miscible gas project, fuel gas would be sent through a chiller to remove natural gas liquids which could be reinjected into the high pressure gas stream creating a Miscible Injectant (MI) for injection into the reservoir. In the early years of operation produced water rates are expected to be low. Produced water wìl1 be separated from the oil stream and commingled with other non-hazardous fluids for injection into a Class 1 or Class II Injection well. Later in the life of the field, as water production rates increase, a produced water handling system will be installed. Formation water will then be commingled with watetflood fluids and reinjected into the Alpine reservoir for pressure maintenance and watetflood support. The CPF also has two seawater injection pumps for injecting seawater into the reservoir for pressure maintenance and watetflood. A 12" seawater pipeline brings treated seawater from the Kuparuk STP to Alpine. Alpine pumps then provide sufficient pressure for injection into the reservoir. The CPF contains the utility systems required to operate a North Slope oil field. Electricity is generated using a General Electric Frame 5 gas turbine as the primary generator. A General Electric PGT 10+ turbine and two internal combustion engines drive backup power generators. Other utility systems include instrument air, nitrogen, plant air, cooling glycol, and heating glycol. Diesel fuel will be provided through a 2-3/8" pipeline from Kuparuk. Production Allocation Production will be allocated to producing wells based on the actual plant oil sales volume and well tests on individual producing wells. All the wells are connected to a test header system, which go to a test meter on CD-2 pad or a test separator in the CPF. Each producing well will be tested at least quarterly to ensure accurate allocation of the produced fluids. Quarterly well testing is requested due to the high concentration of wells per pad and test facility. The most rapid change in well performance is expected during the first year, and monthly tests during that time will identify significant production declines. Unlike more traditionally drilled fields, royalty revenues will be based on reservoir model simulations to identify reserve recovery by section or block. Test data will serve as input to models that allocate reserves by tract based on historic production and injection volumes, reservoir thickness and areal properties, and pressure data. Royalty interests will be redetermined at intervals described in the Unit Agreement. The control system for Alpine will continuously gather operating data from the wells and the test separators. The exact procedure for allocating the production is not detailed here but the following points will be followed: 1. All wells will be periodically tested. 21 e e 2. The stabilization and test duration of each test will be optimized by the Operator to obtain a representative test. 3. Well and field operating condition information required for the construction of a field production history will be maintained. 4. Major test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 5. The Operator will maintain records that permit verification of the satisfactory execution of the approved production allocation methodologies. 22 e e VIII. Summary of Testimony As previously discussed today, oil and gas was initially tested from the Alpine Reservoir in the Bergschrund No.1 in April 1994. Since the initial pool discovery, eight additional penetrations of the reservoir have successfully delineated the pool. Earlier this year, ARCO successfully drilled the first two horizontal wells. Plans are moving forward to initiate a multi-year development drilling program beginning this winter. We are requesting pool rules at this time to provide flexibility moving forward with the development phase. Looking ahead to Alpine start-up in June of 2000, these pool rules provide a basis for ongoing operations that safely protect fresh waters, maximize recovery of the resource, minimize waste and protect ownership correlative rights. Key elements of the pool rule requests include; Definition of the Alpine Oil Pool, Drilling procedures, Well construction plans, Reservoir Surveillance, and Injection procedures. As the results of studies currently underway are finalized this coming spring, we will be requesting an Area Injection Order for the Alpine Oil Pool. At that time we will review a more detailed development plan which we expect to include details of an enhanced oil recovery project for Alpine. ARca Alaska, Inc, Anadarko Petroleum Corporation and Union Texas Alaska, LLC are committed to safe and environmentally sound operations. The pipelines, pads, roads and infrastructure have taken years of planning to minimize environmental impacts within the Colville Delta. Our experiences operating on the North Slope have led to development of numerous 'best practices', which are reflected in these drilling and operating plans. Alpine is our blueprint for 21 st century North Slope field developments that maximize reserve recovery while minimizing environmental impacts. 23 e e IX. Proposed Alpine Oil Pool Rules The rules hereinafter set forth apply to the following described area and are referred to in the order as the affected area: Umiat Meridian Tl1N, R4E Sections 1-5 all, 7-16 all, 21-27 all. Tl1N, 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. Rule 1. Field and Pool Name The field is the Colville River Field, and the pool is the Alpine Oil Pool. Rule 2. Pool Definition The Alpine Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Bergschrund No.1 well between the depths of 6,876' MD and 6,976' MD. Rule 3. Well Spacing Development wells may be drilled initially in line drive patterns on 1,500 feet spacing between well rows. Considering the unique spacing requirements of horizontal wells, and the potential for sidetracks to enhance reservoir management and waterflood recovery, unlimited spacing will be allowed between wellbores of adjacent wells. The reservoir shall not be exposed in any well closer than 500 feet from the boundary of the Alpine Oil Pool. Rule 4. Drilling and Completion Practices a) Upon drilling out no more than 50 feet of new formation within the Alpine Oil Pool, a Formation Integrity Test will be performed. Test pressures will not exceed a predetermined mud weight. b) Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles. c) All ram-type BOPE's, kelly valves, emergency valves and choke manifolds must be pressure tested to the rated working pressure or to the maximum 24 e . surface pressure when the equipment is installed or modified, and at least once every two (2) weeks thereafter. Test results will be recorded as per 20 AAC 25.070(a)(1). d) With respect to deviated wellbores drilled within the Colville River Unit, in lieu of the requirements of 20 AAC 25.050(b), each well's Application for Permit to Drill will include a plan view, vertical section, close approach data, and a directional description. e) In lieu of the requirements of 20 AAC 25.071 (a) a complete electrical log and radioactivity log will be required from below the conductor to TD for only one well on each drilling pad. f) Sufficient and appropriate disposal intervals exist above the Alpine Oil Pool to accept annular injection of drilling waste in AOGCC approved wells. Wells will be permitted and approved in accordance with 20 AAC 25.080 for annular injection. Rule 5. Reservoir Surveillance a) Prior to sustained injection, an initial static pressure survey will be taken in each additional recovery (injection) well. b) A minimum of six (6) pressure surveys will be taken in the Alpine Oil Pool and reported to the Commission annually. Pressure surveys taken as part of Rule 5(a) may fulfill this requirement. c) The reference reservoir pressure datum will be 7000 feet subsea. d) Pressure survey results will be reported to the Commission annually, rather than monthly, on form 10-412, Reservoir Pressure Report. Rule 6. Wellwork Operations The following operations in production and enhanced recovery wells within the Alpine Oil Pool may be conducted without filing an application pursuant to 20 AAC 25.280(a): a) perforate or reperforate casing, b) stimulate, and c) coil tubing operations with the exception of drilling or sidetracks. Rule 7. Automatic Shut In Equipment a) A surface safety valve (SSV) will be installed on all wells. Testing of SSVs will be conducted within six (6) month intervals. Notice of testing will be given to the Commission in time such that a representative of the Commission may be present to witness the work. b) A surface controlled subsurface safety valve (SSSV) will be installed in all new producing wells. Testing of SSSVs will be conducted within twelve (12) month intervals. Notice of testing will be given to the Commission in time such that a representative of the Commission may be present to witness the work. c) At Operator's discretion, SSSV's may be removed in wells producing less than 1,500 BOPD and 5,000 MSCFD 25 e e d) An automatic fail closed injection valve (not surface controlled) will be installed in all injection wells as a subsurface safety valve (SSSV). Testing of SSSVs will be conducted within twelve (12) month intervals. Notice of testing will be given to the Commission in time such that a representative of the Commission may be present to witness the work. Rule 8. Production Practices Well tests shall be conducted a minimum of every 3 months following a well's initial 12 months of production, instead of once every 30 days as specified in 20 AAC 25.230(b). Rule 9. Gas-Oil Ratio Exemption Wells producing from the Alpine Oil Pool are exempt from the gas-oil limit (GaR) set forth in 20 AAC 25.240(b). Rule 10. Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 26 e e List of Exhibits Exhibit 1 Alpine Location Map Exhibit 2 Alpine Oil Pool Section Boundaries Exhibit 3 Bergschrund 1 Type Log Exhibit 4 Alpine Oil Pool Type Log Exhibit 5 Top Alpine Depth Structure Map Exhibit 6 Annular Disposal Type Log Exhibit 7 Phase 1 Development Plan Exhibit 8 Alpine Producer Wellbore Schematic (openhole) Exhibit 9 Alpine Producer Wellbore Schematic ( slotted liner) Exhibit 10 Alpine Injector Wellbore Schematic Exhibit 11 Alpine Class II Injection Wellbore Schematic 27 EXH 1 ALPINE OIL POOL LOCATION MAP 5 Miles Kl.lukpik Unit .: IÞ ? ¡( 2, ¡::1 "" :í .. 1 . 1 n ell .. River Unit .. IBIT 2 Alpine 011 Pool Section 6 5 4 3 2 1 6 5 4 3 2 I 1 7 8 9 11 12 7 8 9 10 10 , 18 17 16 15 14 13 18 17 16 15 13 19 20 21 22 23 24 19 21 24 30 29 u;lt 28 27 31 32 33 35 36 33 34 35 3N.RI4E T1 R' E 4 R4E T12 8 3 2 1 6 5 4 do~ 1 1 6 - 7 8 9 10 11 12 7 8 9 10 11 12 7 AnO~ 1A ... 'l; r~ T n0,n 1 ~ 1 18 15 14 11 18 18 I 22 23 2 7:: ~ ~ 'l; ~ 19 í /ý hAft' ~ /: 28 ~ 30 / 7 7 T f .Rt 34 3 3 31 / 32 . / T1 .. 1 ~ yi)/; 2 II 5 Y II '/I 8 ~ A 8~ ~ ~ / 12 1 It) ell 1 / 13 18 17 1 ~ ~/ ~ 18 / 24 19 20 ~ ~ 1/ 19 2 3 25 30 29 28 v: 'i '7 28 27 26 30 / ~ ¡ '\ Colville River Umt Boundary Alpine Pool Sections I BERGSCHRUND 1 ~ \/I ::J o CIi o " +' CIi - I ALPINE Oil t',"UU I ÿj.JE lOG GR -:w'o~;';') ~ DIE 0 150 1 t : . : ! . : 6840 I·",,··,,··' Z ¡ " . , ¡ 4 F: - :;t(! : ::I: · ¡ : -.., Rule 2. U ~þ i: ¡¡I" The Alpine Oil Pool is defined cC ~ l::::: as the accumulation of oil and W gas common to and correlating > . . ) 6860 ; .' : to the interval found in the 1 =» i :<1-\ . )! i . ;:1 well between 6876 and 6976 ...J -- :E . ; :.....'1 . ; t ; i !¡: · : . <- ~1'J¡"7!1t. ¡. Top Alpine ) ).... T. · ;..- -- ...... . 1\ . 'f 6880 : :' , ; "". ,i i i ., : ( : i , · i ¡ : i '¡ : i Ii! i : i ! 1.1 :\.. : 6900 ! I·! ii; Sandstone, quartzose, i D . , ; l ". ¡ vf-f grained, well sorted, : ! ·.1 H burrowed, glauconitic -- ( :i 0 ¡ 0 " ! : i! D.. ! I . C i . 6920 ! .- I :! Q.. ~ :::: .i :E ¡: : j :/ ! :. . I.L -..... ) i ~ C 0 · . 6940 : Z : Þ . i -- -- ~ ,i~ ¡ Sandstone and Siltstone, ! : i ; : : i i . quartzose, silt-vf grained, : ! 30% matrix, burrowed 6960 ' " : : ',- : '. : , ) ! I", i ..It i¿ ! '. ; ~n..,.~ .. . )! Kingak E · : 6980 · ) ,¡iT : " !¡ i ; , : : ' ." ¡ 1 : . ¡! ! ,1I 1 ¡ . : ¡. ¡ .: i RI= ..U)I R~n 1 ...... U......,I'IIIIJ EXHIBIT 5 TOP ALPINE DEPTH STRUCTURE . 1 . oJ 'U o 1" ::::: 8000' :::::1 1 PERMAFROST UPPER BARRIER (1000 ANNULAR INTERVAL (1800 ft) LOWER . . Exhibit 8 Producer Well bore Schematic (open hole) 16"Conductor @ 100' MD cemented to surface ::;';';' 14-:~ :!~~~~i~ª~~}~~~, ::v ~~" :m¡¡¡: ~I ì~ ~~ .J 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2400' TVD cemented to surface GLM at 3400' TVD with 1" Bottom Latch GL V Packer Fluid mix: 9.2 ppg KCI Brine with 1200' diesel cap 4-1/2" 12.6 ppf L-80 IBT Mod. R28rd Tubing GLM at 5200' TVD 1" Bottom Latch GL V Tubing tail to include DB-6 (3.75"ID) LN and WLEG GLM w/1" Bottom Latch GL V set 2 joints above the X nipple HES"X"LN 2 Jts above packer Packer - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . 6-1/8" Open hole completion interval - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . 7" 26 ppf L-80 R3 10rd BTC Mod Production Casing @ -7000' TVD (90 deg) Updated 11/25/98 e Exhibit 9 . Producer Wellbore Schematic (slotted liner) 16" Conductor to 100' cemented to surface ;¡¡¡m. :mm~ , I=f: 4-1/2" Tubing Retreivable (3.812" ID) SSSV and DB-6 Lock (3.812" ID) with single 1/4" x 0.049" s/s control line @ 1,000' MD 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2400' TVD cemented to surface GLM at 3400' TVD with 1" Bottom Latch GL V 4-1/2" 12.6 ppf L-80 IBT Mod Tubing GLM at 5200' TVD 1" Bottom Latch GL V GLM w/1" Bottom Latch GL V set 2 joints above 'X' LN TOC 500' above Alpine HES"X"LN Set at 60-65 deg Packer Fluid mix: 9.2 ppg KCI Brine with 1200' diesel cap 4-1/2" Liner Assembly: <D - 1 joint blank liner below hanger ® - DB landing nipple ® - blank 4-1/2" liner @- 4-1/2" slotted liner ® - 2 jts 4-1/2" blank liner @- 4-1/2" slotted liner ø - PO & 1 jt 4-1/2" blank liner @- 4-1/2" guide shoe ------------ ----------- ------------ ----------- ------------ ----------- ------------ ----------- ® ---ø-®: -------------------------------------------------------- ---------- ------ 7" 26 ppf L-80 BTC Mod Production Casing @ -7000' TVD (90 deg)cemented 500' above Alpine 4-1/2" 12.6 ppf L-80 R2 8rd IBT Mod. liner Updated 11/25/98 e e Exhibit 10 Injector Wellbore Schematic ~I I 6" Conductor @ 100' MO cemented to surface DB-6 LN (3.812" 10) with Model "A3" SSSV (2.125" 10) at 1000' MO !!!!!~ ""-, 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2400' TVO cemented to surface 4-1/2" 12.6 ppf L-80 IBT Mod.Tubing Packer Fluid: 9.2 ppg KCL brine with N2 or gas freeze protection to 1200' Tubing tail to include OB-6 LN (3.875" 10) and WLEG Packer (3.875" 10) set 60-65 deg above Alpine Sand TOC 500' above Alpine 7" 26 ppf L-80 BTC Mod Production Casing -7000' TVO (90 deg) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . 6-1/8" Openhole completion interval - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - , Updated 11/25/98 · Exhibit 11 KB=52' Measured Depth = TVD I Drilling Mud ~ I Subsea Depths 7300' 7990' 8650' 8700' 9000' 9720' - Class II Injection Well Base Permafrost @ +/-900 ft TVD Cameo 4-1/2" "DB" Nipple (3.812" ID) with Model "A3" Injection Valve (2.125" ID) at -1300' MD 3 Jts below cross-over from STL to IBT-Mod tubing 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2800' TVD 4-112" 12.6 ppf L-80 Tubing STL flushjoint to 1200' 8rd IBT Mod. below 1200' Packer Fluid: 8.6 ppg KCL brine with diesel freeze protection to 1200' Toe @ 6300' TVD (500' above Alpine Reservoir) I ~:'::~, SABL~ Poc~' '. wI KBH-22 Anchor Seal Assembly '" at 8300' TVD I 8550' MD (3.875" ID) Tubing tail to include HES "XN" (3.725" ID) 4-1/2" 10' PJ and WLEG Note-Saker-lock all components Injection perfs 8650-9720' TVD 7-5/8" 29.7 ppf L-80 R-3 STL-FJ to 1200' 7" 26 ppf L-80 R3 10rd BTC-Mod to TD Updated 11/25/98 Ipine iI Production Rate Current Plan of evelopment 80 70 60 50 30 20 10 0 2000 2005 - 2010 2015 2020 ¡me, Years 2025 -- 2030 140 120 100 Alpine as Production Rate Current Plan of Develo ment 80 60 40 en «S 20 " 0 2000 2005 2010 2015 Time, Years 2020 2025 - Alpine ater Production Rate Current Plan of Development 16 14 12 10 8 6 4 2 0 2000 2005 2010 2015 2020 2025 Years "" 400 350 300 "C o 250 L...m 0......... = U) 200 ~ ~ :J o 150 100 50 Alpine Cumulative Oil Production Current Plan of evelopment o 2000 2005 2010 2015 2020 Time, Years 2025 1200 1000 800 600 400 200 Ipine Cumulative Gas Production Current Plan of evelopment o 2000 2005 2010 2015 2020 2025 2030 Time, Years - 50 45 40 35 CD 30 I- U) 25 :e CD 20 > ....... ...... m 15 ...... :J E 10 :J 0 5 0 2000 Alpine Cumulative Water Production Current Plan of Development 2005 2010 2015 2020 Time, Years 2025 - Alpine Production Rate Forecast Current Development Plar Oil Rate Water Rate Gas Rate Cumulative 011 Cumulative Water Cumulative Gas MSTB/Day MBBUDay MMSCF/Day MMSTB MMBBL BSCF 2000 42.2 0.0 34.5 15.4 0.0 12.6 2001 72.3 0.0 64.0 41.8 0.0 35.9 2002 66.2 0.0 66.1 66.0 0.0 60.1 2003 64.3 0.0 87.9 89.5 0.0 92.1 2004 57.7 0.0 113.0 110.5 0.0 133.4 e 2005 50.6 0.0 118.7 129.0 0.0 176.7 2006 41.7 0.0 110.3 144.2 0.0 217.0 2007 39.4 0.0 107.5 158.6 0.0 256.2 2008 38.9 0.0 108.9 172.8 0.0 296.0 2009 37.9 0.1 107.7 186.6 0.0 335.3 2010 36.9 0.3 106.7 200.1 0.1 374.2 2011 35.2 1.1 106.5 212.9 0.5 413.1 2012 34.2 1.5 104.6 225.4 1.1 451.3 2013 33.2 1.9 104.9 237.5 1.8 489.6 2014 32.2 2.2 106.8 249.2 2.6 528.6 2015 30.8 2.5 106.8 260.5 3.5 567.6 2016 29.1 2.9 105.7 271.1 4.5 606.2 2017 27.6 3.4 102.3 281.1 5.8 643.5 2018 26.2 3.9 98.0 290.7 7.2 679.3 2019 24.6 4.5 93.5 299.7 8.9 713.4 2020 22.8 5.3 88.6 308.0 10.8 745.8 2021 21.3 6.1 84.7 315.8 13.0 776.7 2022 20.0 7.1 82.8 323.0 15.6 806.9 - 2023 19.0 8.2 80.5 330.0 18.6 836.3 2024 18.2 9.3 77.9 336.6 22.0 864.7 2025 17.3 10.4 74.4 342.9 25.8 891.9 2026 16.4 11.4 71.0 348.9 30.0 917.8 2027 15.4 12.4 67.4 354.5 34.5 942.4 2028 14.3 13.3 64.3 359.7 39.4 965.9 2029 13.3 14.3 61.6 364.6 44.6 988.4 Notes: 1. Alpine Current Development Plan assumes 92 wells (32 horizontal, 60 conventional) and Waterflood Injection in Center of the Field and Gas Re-injection Around the Periphery of the Field. 2. Alpine assumed to start-up in June, 2000 3. End of field life assumed to be 1/1/2030 Alpine Production Rate Forecast Current Development Plar Oil Rate Water Rate Gas Rate Cumulative Oil Cumulative Water Cumulative Gas MSTBlDay MBBUDay MMSCFlDay MMSTB MMBBL BSCF 2000 42.2 0.0 34.5 15.4 0.0 12.6 2001 72.3 0.0 64.0 41.8 0.0 35.9 2002 66.2 0.0 66.1 66.0 0.0 60.1 2003 64.3 0.0 87.9 89.5 0.0 92.1 2004 57.7 0.0 113.0 110.5 0.0 133.4 2005 50.6 0.0 118.7 129.0 0.0 176.7 e 2006 41.7 0.0 110.3 144.2 0.0 217.0 2007 39.4 0.0 107.5 158.6 0.0 256.2 2008 38.9 0.0 108.9 172.8 0.0 296.0 2009 37.9 0.1 107.7 186.6 0.0 335.3 2010 36.9 0.3 106.7 200.1 0.1 374.2 2011 35.2 1.1 106.5 212.9 0.5 413.1 2012 34.2 1.5 104.6 225.4 1.1 451.3 2013 33.2 1.9 104.9 237.5 1.8 489.6 2014 32.2 2.2 106.8 249.2 2.6 528.6 2015 30.8 2.5 106.8 260.5 3.5 567.6 2016 29.1 2.9 105.7 271.1 4.5 606.2 2017 27.6 3.4 102.3 281.1 5.8 643.5 2018 26.2 3.9 98.0 290.7 7.2 679.3 2019 24.6 4.5 93.5 299.7 8.9 713.4 2020 22.8 5.3 88.6 308.0 10.8 745.8 2021 21.3 6.1 84.7 315.8 13.0 776.7 2022 20.0 7.1 82.8 323.0 15.6 806.9 - 2023 19.0 8.2 80.5 330.0 18.6 836.3 2024 18.2 9.3 77.9 336.6 22.0 864.7 2025 17.3 10.4 74.4 342.9 25.8 891.9 2026 16.4 11.4 71.0 348.9 30.0 917.8 2027 15.4 12.4 67.4 354.5 34.5 942.4 2028 14.3 13.3 64.3 359.7 39.4 965.9 2029 13.3 14.3 61.6 364.6 44.6 988.4 Notes: 1. Alpine Current Development Plan assumes 92 wells (32 horizontal, 60 conventional) and Wateñlood Injection in Center of the Field and Gas Re-Injection Around the Periphery of the Field. 2. Alpine assumed to start-up in June, 2000 3. End of field life assumed to be 1/1/2030 . 11________________ Ou'tline of Oral Testimony* Alpine Pool Rules Hearing Introduction Geology Reservoir Drilling . Well Operations Facilities Summary Mark Ireland Doug Knock Mark Ireland Doug Chester Mike Erwin Brian Richards Mark Ireland e e OR J Gl NAL *Written testimony has been filed. December 3,1998 ------------------- Alpine Pool Rules Hearing Summary of Proposed Pool Rules 1. Field and Pool Name 2. Pool Definition 3. Well Spacing 4. Drilling & Completion Practices 5. Reservoir Surveillance 6.. Workover Operations 7. Automatic Shut-In Equipment 8. Production Practices 9. Gas-Oil Ratio Exemption 10.. Administrative Action I:NE e e December 3,1998 ------------------ Rationale for Proposed Pool Rules Alpine Pool Rules Hearing The Alpine Development will first and foremost protect health, safety, and the environment while conserving Alpine resources. e Proposed Alpine Pool Rules will: · prevent waste and promote conservation; · protect correlative rights; · and promote maximum ultimate recovery. e December 3. 1998 .------------------ Alpine Pool Rules Hearing AI L . Hi f- _ . _pIne as..ory 1994 Discovery well - Bergschrund #1 1995 Confirmation wells Alpine 1, 1A, & 18 Fiord 3 & 3A 1996 Delineation Wells Alpine 3 Bergshrund #2 & 2A Nanuk 1 Neve 1 1998 Wells - First on permanent pads CD1-22 CD2-35 e e December 3, 1998 ------------------- Alpine Pool Rules Hearing Alpine Owners -Royalty Owners · State of Alaska · Arctic Slope Regional Corporation - -Working Interest Owners · Arco Alaska, Incorporated · Anadatko Petroleum Corporation · Union Texas Alaska 56% 22% 22% . December 3.1998 1_______________ Alpine Pool Rules Hearing Geology · Alpine Pool Geology · Cretaceous Annular Disposal Geology · Triassic Waste Disposal Geology e e December 3, 1998 .. .. .. .. .. .. .. - .. .. .. .. .. - .. .. - .. .. EXHIBIT 1 Oil POOllOCA TION MAP 5 Miles 1 iIIJ Kalubik illJTex ø filE. Ugn 1 Kuparuk River Unit j @I Sine CI11 . k 1 Tarn #1 #1 «II , , , " " " , " , , , , , NPRA. , " , , " , " , " " , , , " " , , " , I I I I I I I I I I I I I I I I I I I EXHIBIT 2 Alpine Oil Pool Section Boundaries ~1fE II 5 5 to4 8 9 10 4 3 2 6 3 2 1 1 7 8 7 9 10 11 12 18 17 16 15 14 13 19 20 21 22 23 24 30 29 28 27 18 11 16 15 13 19 ~~ 21 24 ."..... - "'It> 28 27 33 35 32 34 T13N R E T12N R5E 5 4 I"rOR 1 2 1 6 _II 8 9 10 11 12 7 31 6 '" ,.~ ., L 18 32 T 35 36 4E 3 2 1 II 8 9 10 11 rEM Hmo~ HI - r ~I0.n 1 15 14 12 ., lK1 ~~~ 111 111 17 16 1/~~Z~V 19 3 ~ ~ ~/'6 30 .L / 3 .. ~ 1 ~V 7 / 2/ / 2 /~~ 5 V 4 111 /~~1 19 28 27 26 25 30 r- Colville River Umt Boundary Alpine Oil Pool Sections 22 23 hV Z 5 33 R 1 L 4 2 L / 9/~~ 12 II 13 18 7;/;; 24 19 20 21 ~ / 25 30 29 28 ~ I I I I I I I I I I I I I I I I I I I EXHIBIT 3 BERGSCHRUND 1 TYPE lOG ------------------- Geology Alpine Pool Rules Hearing Rule 2. Pool Definition The Alpine Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Bergschrund #1 well between the measured depths of 6876 and 6976. - e December 3, 1998 -------------......-..- EXHIBIT 5 TOP ALPIN DEPTH STRUCTURE . 1 1 ~ . . oj c SCALE 1" ::: 8000' C.I, ::: 100' I I I I I I I I I I I I I I I I I I I t :E II.. Z U III( ~ :J ..JI -- :E ,... Î\ )1\ -- o o a.. . c .... A, ë ~ III( c z SC EXHIBIT 4 ALPINE OIL POOL TYPE LOG GR 150 I~_L.L L i IUj ¡ -F-h! í~ I ~N / <-..; 1'\ . I i '.-1 I~¡ ¡ i i<P 1 '-- i IT'( I ! L> I I ( I ~ I : I I \ I : ¡ I ! i I! I i! i I i i 'I' I I I. j i ~ Þ (" ! 1 . ~I~ 11) , ') I 1_, ! : ,i ".Q I ! i <' ~ \ <... \I I ¿] I , I ! ! ! , i ¡ " i !f¡M í j J , ! I I ! : ! ¡. I t1 I-I: 69';1, ¡r:::r= , I ·Ii! ; i', ¡ !¡i ¡)ì , i ¡ Ii! I I I BERGSCHRUND 1 i I I ! ~.' ) ~ ; J: ,,¡ <' ~ 6860 _... 6880 , i I \ i ! I 6900 I 6920 6940 6960 DlB 1 Resistivity 100 i I pi ¡ ¡ ¡ I IRlI.lle 2. : The Alpine Oil Pool is defined ¡ i I as the accumulation of oil a~d i ! I i gas common 10 and correlating ¡Ij i I ¡ well between 6876 and 6976 MD. ! i 1111,.' ! I. i i i!, I I" , I i I I ,,"J,.~..,~J' I 1'1 ill' ! ,I, 6816 " Top Alpine , I li:I I ! í' I ,"I, II': '\') ! ! ¡1¡ ! Ii! ! ¡ Ii I : . I :1, I II I II I i í I ! I",,.,.m I Sandstone, q¡uartzose, Ii, I': vf-f grained, well sorted, i ¡If 1; , III, , I :¡ I, f! 'I '. ii II Ii ': ¡¡ ~1MH+~: i Sandstone and Siltstone, q¡uartzose, siBt-vf grained, i i !! 30% matrix, burrowed I'il) . , ; i ~1~1 ,ifI Kingak E. I!: I Bergschrund 1 I I PERMAFROST I (850 it) I I I I UPPER BARRIER (1000 ft) I I . . I ANNULAR DISPOSAL INTERVAL I (1800 ft) I I I I (700 ft) I I -------------------- Alpine Pool Rules Hearing Annular Disposal Geology · Surface casing set at 2350 sstvd · Annular disposal interval · Upper Cretaceous Seabee & Torok Formations · 1800 feet of interbedded sandstone & shale · Disposal interval is continuous over several miles · Upper Barrier · Upper Cretaceous Schrader Bluff Formation · 1000 feet of shale & siltstone · Permafrost · 800 to 950 feet thick e e December 3, 1998 --------~~-~------- Alpine Pool Rules Hearing Triassic Waste Injection Class 1 Industrial Waste Iniection Well · WD2 - Drill in February 1999 · Lower Injection Zone · Upper Triassic Ivishak Sandstone · Upper Injection Zone · Upper Triassic Sag River Sandstone · Upper Confining and Arresting Zone · Jurassic Kingak Shale · 1100 feet of marine shale - - December 3,1998 I I I I I I I I I I I I I I I I I I I CJ. =:: 50' I WASTE DISPOSAL INJECTION TYPE LOG I NECHElIK I I UPPER CONfINING ZONE I (400 ft) I KINGAK I I UPPER ARRESTING ZONE I (100 ft) I I 1lJI. INJECTION ZONE SAG RIVER 1 $Wo aye porosity 35 ft net sand I SHIlJIBlIK - BARRIER I EILEEN I I lOWER IVISHAK INJECTION ZONE I 16% aye porosity 400 ft gross sand 19 ft net sand I I KAVIK lOWER CONfiNING I ----~-----~-------- Alpine Pool Rules Hearing Reservoir rV1echanisms and Development Plans Reservoir Properties e Recovery Mechanisms Development Plans Optimization Plans e Proposed Pool Rules December 3, 1998 ------------------..- Reservoir Properties ~NE Alpine Pool Rules Hearing Average Porosity Permeability Average Water Saturation OOIP Oil Quality Oil Viscosity Initial Pressure Bubble Point Pressure Gas Cap Aquifer 190/0 1-160 md 190/0 1 Billion STB 39 Degrees .45 3175 psig 2450 psig None None e e December 3, 1998 --~--------~----~~- Alpine Pool Rules Hearing Recovery Mechanisms Injectant Import Options · None (Primary Recovery) · Water · Lean Gas · Miscible Injection e e December 3, 1998 -------------..----- Alpine Pool Rules Hearing Recovery Mechanisms Water Import with Gas Re-injection · Selected Based on Ultimate Recovery and e Economics · Major Risk is Low Water Injectivity · Contingency Plans to Convert to Gas Injection e December 3, 1998 ------------~----~- Alpine Recovery - Current POD 50% 45% Q. 40% Õ 35% 0 -- ~ -- -- 30% -- - 25% -- -""... .... ". Upside WF 20% 15% .. .. .. . Expected WF - - - - Downside WF 10% lean Gas Flood I 5% ill Miscible Flood 0% 2000 2005 2010 2015 2020 2025 2030 December 3, 1998 ------------------ Development Plans Alpine Pool Rules Hearing Current Development Plans · Phase I - Core Area Development 50 Wells drilled to a 600 md-ft cutoff 32 Horizontal Wells (275 Acre Spacing) 18 Vertical Wells (160 Acre Spacing) · Phase II - Peripheral Area Development 42 Wells drilled to a 200 md-ft cutoff All Vertical Wells{160 Acre Spacing) · Water Injection in the Center of the Field · Gas Re-injection around the Periphery e e December 3, 1998 ------------------- Development Plans Alpine Pool Rules Hearing Proposed Revised Development Plans · Core Area Development 82 Wells drilled to a 600 md-ft cutoff All Horizontal Wells (140 Acre Spacing) · Phase II - Peripheral Area Development 56 Wells drilled to a 200 md-ft cutoff All Horizontal Wells (140 Acre Spacing) · Miscible Water-Alternating-Gas Injection e e December 3, 1998 ------------------- Alpine Pool Rules Hearing Optimization Plans Optimization · Multiple Target Wells Longer Horizontal Wells Multi-Lateral Wells · Infill Drilling · Miscible Injection Optimization MI Enrichment Reservoir Pressure MI Expansion Strategy MI WAG Ratios and Cycle Lengths e e December 3, 1998 ------------------- Alpine Pool Rules Hearing Proposed J')ool Rules Reservoir Development Pool Rules · Spacing (Rule 3) · GOR Exemption (Rule 9) e e December 3, 1998 ------------------- J)roposed Rule 3 Alpine Pool Rules Hearing Spacing Units · No Minimum Spacing · No Closer than 500' from Ownership Change e e December 3, 1998 ------------------- Alpine Pool Rules Hearing Proposed Rule 9 GOR Exemption · Exempt from Producing GOR Limits e e December 3, 1998 ! 1______-__.._-_-_- Alpine Pool Rules Hearing ·Justification for Rule 3 Potential Need to Sidetrack Wells near Existing Wells · Isolate High Permeability Zones for Off-take Management · Modify Injector or Producer Profiles to Improved Recovery I:N'E e e December 3, 1998 1_______________-__ Alpine Pool Rules Hearing Justification for Rule 9 GOR Exemption · Gas returned to the pool for pressure management and enhanced recovery e e December 3, 1998 ------------------- Drillina Practices - Alpine Pool Rules Hearing -Cemented & Insulated conductor set at a minimum e of 75 feet below pad level -Surface casing set below permafrost and cemented to surface -Single stage surface cement jobs with top jobs and port collars for contingency -BOPE installed and tested before drilling out e casing -Perform LOT December 3. 1998 ------------ ..------ Alpine Pool Rules Hearing Drilling Practices [I] ----- - - - -Use "Bump & Run" well design e -Set intermediate casing in Alpine zone -Periorm FIT in Alpine zone -Drill horizontal section -Displace mud to diesel -Complete open hole e -Run completion December 3, 1998 ------------------- Alpine Pool Rules Hearing Drillina Practices - -Survey's will be with MWD -Logging by LWD in zone. -Batch drill to reduce material storage -Single BOP rig up -Through bore wellhead system -Horizontal wellhead system -Typical North Slope mud systems e -- December 3, 1998 ------------------- e I -No USDW's -Ball mill capable of grinding or washing grave -Inject down 9 5/8" x 7" annulus -Injection zone - Top of Seabee -Confining zone - Schrader Bluff -1000 ft below West Sak Alpine Pool Rules Hearing AI1nular Disposal e 1998 December 3, ------------------- rilling Practices (Rule 4) Alpine Pool Rules Hearing ·a) Upon drilling out no more than 50 feet of new formation e within the Alpine Oil Pool, a Formation Integrity Test (FIT) will be peñormed. Test pressures will not exceed a predetermined mud weight. ·b) Alternate casing and completion programs, in addition to those specified in the regulations, may be administratively approved upon application and presentation of data which e demonstrate the alternatives are appropriate, based upon sound engineering principles. December 3, 1998 ------------------- - (2) (Rule 4) ·c) All ram-type BOPE's, kelly valves, emergency valves and choke manifolds must be pressure tested to the rated working pressure or to the maximum surface pressure when the equipment is installed or modified, and at least once every two weeks thereafter. Test results will be recorded as per 20 MC 25.070(a)(1 ). Alpine Pool Rules Hearing ngPractices D rUIi e 1998 December 3, ·d) With respect to deviated wellbores drilled within the Colville River Unit, in lieu of the requirements of 20 MC 25.050(b), each well's Application for Permit to Drill will include a plan view, vertical section, close approach data, and a directional description. ------------------- Drilling Practices (Rule 4) 1:1VE Alpine Pool Rules Hearing -e) In lieu of the requirements of 20 MC 25.071 (a) a complete electrical log and radioactivity log will be required from below the conductor to TD for only one well on each drilling pad. e -f) Sufficient and appropriate disposal intervals exist above the Alpine Oil Pool to accept annular injection of drilling waste in AOGCC approved wells. Wells will be permitted and approved in accordance with 20 MC 25.080 for annular injection. e December 3. 1998 ---~---~---~~-~~--- Alpine Pool Rules Hearing Well Operations Overview -Well Completions -Sidetracks -Reservoir Surveillance (Rule 5) -Workover Operations (Rule 6) -Safety Valves (Rule 7) e e -Class II Injection Well Completion Design December 3,1998 ---~-~~------~--~-- Alpine Pool Rules Hearing Alpine Producer eo openhole -16" conductor at 115' -9-5/8" surface casing at 2400' - 7" production casing set at approximately 7000' in the Alpine at 90 deg -Surface controlled SSSV at 1000' -3 gas lift mandrels -4-1/2" tubing e e roc 500' abo.ve Alpine .!" '¡~I' Packer ·t~~ .:~~: 7000' TVD at 90 deg l:'!;r:f;.:.:.:. __"'_"'"0_ -'__:.;..._. '.,. ........_... 6-1/8" Openhole . . . . . ~.Q!'Tt.P!~tlønl!1t~!'V~I... ..: December 3,1998 ~--~~-~-----~-~~~~- Alpine Pool Rules Hearing Alpine Producer... slotted liner -16" conductor at 115' -9-5/8" surface casing at 2400' -7" production casing set at approximately 7000' in the Alpine at 90 deg -Surface controlled SSSV at 1000' -3 gas lift mandrels -4-1/2" tubing -4-1/2" slotted liner e . TOC 500' above Alpine Combo packerlllner hanger ------ - ---- ----, December 3. 1998 ---~~----~---~----- Rules Hearing njector Alpine Pool I Alpine e -16" conductor at 115' -9-5/8" surface casing at 2400' · 7" production casing set at approximately 7000' in the Alpine at 90 deg e -Automatic fail closed SSSV at 1000' (not surface controlled) -4-1/2" tubing Toe 500'above Alpine 1998 December 3. 6-1/8" Openhole Interval '~~~~~ '\¡.~~ "1¡¡!ì¡¡~~ ..G~~;~ -..-..---------------- 1998 December 3, 1500 ------~-~--~---~--~ I 1000 I I 1 3000· . I Fault --~---~-~----~~~-~~ Reservoir Surveillance (Rule 5) Alpine Pool Rules Hearing ea) Initial SBHP in all Class 2 wells · represents -1/2 wells drilled · best source of initial pressures · 5-8 year drilling program planned eb) Minimum of 6 SBHP's annually · Lengthy buildup times (function of well length) · Focus - extrapolating PBU's from inj wells ec) Reference datum at 7,000 ft TVDSS ed) Annual reporting e e December 3, 1998 -------------~-~--- 3000' Horizontal Producer after 1 year at 3,000 BOPD Test Peri 3000 « . . . - -. -.. -. - . nalysis --IIII~ Design A on Flow Rate - - .. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~ ~ ~ - - - ~ ~ - - - - - - - - _ 1 _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ 2000 - - - - - - - - - - - - - - - - - - - - - - - - - - 1500 -10000 2800 - - - - - - - ,.-..... ~ 1800 0 ~ r:/J "-"" (1) ~ ~ I - - q . . - . . . .. .... -. 800 -200 ---------------~~-- TOP ALPIN DEPTH STRUCTURE . 1 1 ~ . . oJ 'U 67" 3· o SCALE 1" = 8000' Col. = 100' -~----------~~-~~-- Alpine Pool Rules Hearing WeUwork Operatiol1S (Rllle 6) -The following operations in production and enhanced recovery wells within the Alpine Oil Pool may be conducted without filing an application pursuant to 20 AAC 25.280(a): · a) perforate or reperforate casing · b) stimulate, and · c) coil tubing operations with the exception of drilling or sidetracks. e e December 3. 1998 -~---~----~-~~----- Alpine Pool Rules Hearing Automatic Sl1ut-in Equipment (Rule 7) -a) An automated surface safety valve (SSV) will be installed on all wells. Testing will be conducted within 6 month intervals and coordinated with the Commission. -b) A surface controlled subsurface safety valve (SSSV) will be installed in all new producing wells. Testing will be conducted within 12 month intervals and coordinated with the Commission. -c) At Operator's discretion, SSSV's may be removed in wells producing less than 1,500 s~po and 5,000 MSCFO. -d) An automatic fail-closed injection valve (not surface controlled) will be installed in all injection wells as a subsurface safety valve (SSSV). Testing will be conducted within 12 month intervals and coordinated with the Commission. e e December 3.1998 -----------~------- Bae. Pormaf'rost @+I-800 ft 'J'VDsg ~1 cond 11 ~9-5/8 surface casi 2800' production casing at , MD/10,050' ng 1 , II!! @I valve at 1300' t @ ·Sad :hitlSag River perforations 500' above 1998 December 3, 'I'D 9957' i\ID 16,322 MD. ---~--------------- December 3. 1998 December 3, 1998 \ ------------------- ------------------- Facilities Alpine Pool Rules Hearing · INFRASTRUCTURE · CAMP · WAREHOUSE · SHOPS · WASH BAY · CLASS 1 DISPOSAL WELL · RUNWAY · POWER GENERATION · TELECOMMUNICATIONS e e December 3. 1998 ------------------- Alpine Pool Rules Hearing F""'" ,,¡!It" !. aCIJleS ColvmeField Boundary ~ _._._._._._._.,~..._.._ _ ~'_'_'_"_'_'_"_'_'_'_'_~_'_'_"_'_~~'._'_'!_'~_"_'_._.._r~ I . \ I e I J I I 1 I J I I Seawater from Kuparuk \ I Fuel Gasto>Nuic~sit .. ,,'.... I ... Fue~gas I -- .GAS.COMPRESSION ..... .' ... ... I .' & CONDITIONING Artificial lift I -.; ., .... t Gas Reinjectioni c ....; ell Stream ... I Fluids I OIL SEPARATION I - ... &.PROCESS1NG Sales on . I -- I I I . Water toDlspolali ..:,. . , . ... !w I e I - I ... I ) .... ... Pumps Watert1oodlnjection "_.~._._._._._.- _._'--'~'~'~'-.'-'-~~.-'~' -"-"~'-'-"-"'-'~'-'~'-~-"-'-"~~~~-~~' ------------------- Alpine Pool Rules Hearing Facilities · OIL SEPARATION e · 3 MAIN VESSELS · OIL HEATING · SHIPPING PUMPS · CRUDE SALES METERING · WATER DISPOSAL PUMPS e December 3,1998 ---..........----..--..--- '" I December 3,1998 ------------------- Facilities Alpine Pool Rules Hearing · GAS COMPRESSION & CONDITIONING e · LOW PRESSURE COMPRESSOR -. SINGLE STAGE - ELECTRIC DRIVER · HIGH PRESSURE COMPRESSOR THREE STAGE - TURBINE DRIVER · GAS DEHYDRATION e · SINGLE TRAIN DESIGN December 3.1998 ------------------- Alpine Pool Rules Hearing Facilities ·Production Allocation · Actual sales volumes · Reservoir modeling · Individual well tests Monthly for 1 year Quarterly thereafter · Single zone reservoir · High well density per pad · Full open chokes · Single train separation (150 psi) - e December 3. 1998 #3 . . . - FACSIMILE TRANSMITTAL SHEET DATE: ~ \ J 1 /1 ð I TO: ~^ FAX #: X7 ~o - t..- " FROM: \Y\ ,\Lt ~JwvV'-- ~ '(j v (ì...fI( &: vV\ t C, ~ '- v"'\ c... \ \l> ~~Á ) \ Õ s-o v--& ~ \A \-.{ -~1 ~~ð~ COMMENTS: NO. OF PAGES FOLLOWING COVER: ., FAX NUMBER (907) 265-1515 VERIFY NUMBER (907) 263-4414 t\CvCJvt:D HOV 091998 Alaska Oil & Gas Cons. \ÍOffllTlISSÎOO Anooorage . . IX. Proposed Alpine Oil Pool Rules The rules hereinafter set forth apply to the following described area and are referred to in the order as the affected area: Umiat Meridian T] IN, R4E Sections 1-5 all, 7-t6 all, 21-27 atL T 11 N, R5E Sections 1 ~24 alt, 29-30 all. Tl2N, R5E Sections 13-15 all, 19~36 all. t\Cvclvt:D NOV 09 1998 Alaska 04f & Gas Cons. Commis&ion And10rage T12N, R4E Section 24, 25-27, 33-36 aU. Rule 1. Field and Pool Name The field is the Alpine Field and the pool is the Alpine Oil Poo1. Rule 2. Pool Definition -po- The Alpine Oil Pool is defined as the accumulation of oil and gas common to and cOlTelating to the interval found in the Bergschrund No.1 well between the depths of 6,876' MD and 6,976' MD. Rule 3. Well Spacin2 The requirements of 20 AAC 25.055 are waived for development well~ in the Alpine Oil Pool. Development weBs will be drilled initial1y in line drive pattert1s on 1,500 feet spacing between well row~. Unhmited spacing will be allowed between well bores of adjacent wells. The reservoir shall not be ex:posed in any well closer than 500 feet from the boundary of the Alpine Oil Pool. Rule 4. DriIJin2 and Completion Practices a) Upon drilling out no more than 50 feet of new forma.tion within the Alpine Oil Pool, a Formation Integrity Test will be petfonned. Test pressures need not exceed the fracture gradient of the Alpine Oil Pool. b) Alternate casing a.nd completion programs may be a.dministratively approved by the Commission upon application and presentation of data which demonstrate the nlternatives are appropriate, based upon sound engineering principles. ç) All ramfttype BOPE's, kelly valves, emergency valves and choke manifolds must be pressure tested to the rated working pressure or to the maximum surface pressure when the equipment is installed or modified, and at least once 23 . . every two (2) weeks thereafter. Test results will be recorded as per 20 AAC 25.070(a)( I). d) The detailed pennitting requirements for deviated wellbores in 20 AAC 25.050(b) are waived for development wells in the Alpine Oil Pool. e) The requirements of 20 AAC 25.071(a) are waived. A complete electrìcallog and radioactivity log will be provided for one well on each drilling pad. Additional wells wiJl not be logged across the follle:ngth of tht; w~ll, except at Operator discreÜon. o The requirements of 20 AAC 25.030(g)(3) are amended to require cement bond logs on all injection well casings smaller than 7", rather than 9-5/8". g) Disposal of drilling waste through the surface casing annular space, 20 AAC 25.080, in Alpine wens is authorized. Rule 5. Re..liiervoir Surveillance a) Pdor to sustained injection, an initial static pressure survey will be taken in each injection well. b) A minimum of six (6) pressure surveys will be taken in the Alpine Oil Pool and reported to the Commission annually. Pressure surveys taken as part of Rule Sea) may f1.l1filJ this requirement. c) The reservQir pressure datum for reporting will be 7000 feet subsea. d) Pressure survey results will be reported to the Commission annually on form 10-412, Reservoir Pressure Report. Rule 6. \y. orkover Operations The requirements of 20 AAC 25.280(a) are waived for development wells in the Alpine Oil Pool. Rule 7. Automatic Shut In Equipment a) Testíng of surface safety valves (SSV) will be conducted within twelve (12) month intervals. Notice of testing will be given to the Commission in time such that a representative of the Commission may be present to witness the work. b) A subsurface safety valve (SSSV), installed at Operator discretion, must be maintained in working order and is subject to performance testing comparable to the surface safety valve (SSV). Rule 8. Production Practices The requirements of 20 AAC 25.230(b) are waived allowing well tests to be conducted a minimum of every 3 n)onths following the well's initial 12 months of production. 24 ~ ~i .ø- m ~\~ ..."'~) ~ 'ß.wIt.Jf~~ ¥! ~L.;;! NOV 09 1998 AIa8b œ & Gas Cons. comulIS$ÍC1I1 Anthomge . . Rule 9~..Gas-Oil Ratio Exemption Wells producing from the Alpine Oil Pool are exempt from the gas-oillirnit (GOR) set forth in 20 AAC 25.240(b). Rule 10. Administrative Acti.2!! Upon proper application, the Commission may adminiSlratively wajve lhe requirements of any rute stated above or administratively amend the order as long as the change does not promote waste, jeopardize cOITelative rights, and is based on sound engineering principles. ~. .. c'. ... .~ rð sr- I) ~J! IP"" ¡1 j). t~, ~" '~Ä.'W.":~'~:,~ t..'JiI£Zt ~ Y.::g ~!II)j Zb,J NOV 09 ]998 ¡~askí: tJij & Gas Cons. Commission lìnœ~ 25 #2 . . U ['\\j ,\ L Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Alpine Oil Pool Notice is hereby given that ARCO Alaska, Inc. has petitioned the Alaska Oil and Gas Conservation Commission under 20 AAC 25.520 to hold a public hearing to present testimony to establish pool rules for the Alpine oil accumulation located approximately 20 miles west of the Kuparuk River Field in the Colville River delta area on Alaska's North slope. A hearing will be held at the Alaska Oil and Gas Conservation Commission, 3001 Prcupine Drive, Anchorage, Alaska 99501, at 9:00 AM on December 3, 1998 in conformance with 20 AAC 25.540. All interested persons and parties are invited to present testimony. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana FIe k at 793-1221 no later than November 23, 1998. Published October 16, 1998 ADN A002914007 #3000 STOF0330 AO-02914007 $49.14 . . AFFIDAVIT OF PUBLICATION STATE. OF ALASKA. THIRD JUDICIAL DISTRICT. Eva 11. Kaufmann -CLlP- 10/16/98 1Iofdot PUb~~itjg" STATE Of' ALASIS,A A\øSI<G~i(I~~ COJlServa~~n Re:- Alpi~ Oil Poqt Notice is hereby gl'!"n '!ml ARCO Alaska, Jnc.' .: tiOned the Alasl«¡ Conservation cler 20 AAC public hearing mOnY to. est . for the Alpine oil. .. loon located approxirnatèIX2îI .. '. miles west of ~ ;!(uP!lruk: River. Field in the Ç.9IvJIIe! River delta area .QnvA\Þ!la's North SloPe. '4 hearing Aid tion Par Alaska [)ecember-~;.T~II:. . . . .. .. . mance with 20 AAC 25.5.tO. All interested persons and. po~ties are invited· to ,present tesltmo- nY. . ' . h If YOU ore.a person WI, . II disobility· who may need a special modification in order to. commentqT to, attend the public hearing, please contact Diana Fleck at 793-.1221 no latêr than November 23, 1998. fs/David W. Johnston ' çhairman. . ADN A002914007 Pub;: Oct.J6; 1'19& . ................................................... being first duly sworn on oath deposes and says that he/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 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. signed ,12h1tJrì.-. ~ ~- tÍ0"Zt U.cMJ II rJJ ill) (j OJ ð,,- ~Ü6~~ribed and svJd·~·Ytð'UíYe~\..N me this!i~ day oflì~.I?eß- 1 9. CZ i If· t \ \ \. \.:' ,[,[{·¡/,ro(( (' /"¡r ~~ \\. "'~,,t, t;;"'di,,}.....:¡F/ \. \. '.f',~ ;,\. .. . . . .> ~ ¿'t'J~!, r \..'" ,v· ,~.....'"" 0..«,'-;:" .............. ..:"........ . ... ........ '\-;..~. ',.,. C,"'it c,. ,Î"< . 5~-::' ~ ...."Ì~ "_:::~ v.'.þ ~.~ "-=' Notary Pu lie in and for :::: . . ~ the State of Alaska. :::: . ::::: Third Division. ::::.. ~" k~ ...::::: Anchorage. _ Alaska ~.. .. :;)~ "'...., {~:\t4.. .. .::?:: MY COMMISSION EXPIRES -:;:, - <; o\~ A'l""': . y , ;a ~ "':..:. \) o /./.1 ,ß( ,\ ........... .. . .......O............y..2 'ðlJfl#fJJ))Ì) \ Search Results for Anchorage Daily News .ed Onlòitp://search.nando.netJPlweb-Cgil..~%20%28LEGALS%29%3ACategory%20 [ Anchorage Daily News I Today's Classifieds I Sunday's Classifieds ] Requested Classified Ad """"."". 'M..".~.,.",.'M'.m..,·_~. n. .··.w"·""w.__··__________"'~",...ww,, Copyright © 1997 Anchorage Daily News 1 of 1 10/16/989:39 AM 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 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 e ?L~ ~1 PIRA 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 AMERICAN PETR INST STAT SECT JEFF OBERMILLER 1220 L ST NW WASHINGTON DC 20005 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 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON DC 20585 US GEOL SURV LIBRARY NATIONAL CTR MS 950 RESTON VA 22092 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 e TECHSYS CORP BRANDY KERNS PO BOX 8485 GATHERS BURG MD 20898 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 '(JNIV OF ARKANSAS SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE AR 72701 e CROSS TIMBERS OPERATIONS SUSAN LILLY 210 PARK AVE STE 2350 OKLAHOMA CITY OK 73102-5605 IOGCC POBOX 53127 OKLAHOMA CITY OK 73152-3127 CH2M HILL J DANIEL ARTHUR PE PROJ MGR 502 S MAIN 4TH FLR TULSA OK 74103-4425 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 OIL & GAS JOURNAL LAURA BELL POBOX 1260 TULSA OK 74101 R E MCMILLEN CONSULT GEOL 205 E 29TH ST TULSA OK 74114-3902 MARK S MALINOWSKY 15973 VALLEY VW FORNEY TX 75126-5852 PURVIN & GERTZ LIBRARY 1201 MAIN ST STE 2600 DALLAS TX 75202 DEGOLYER & MACNAUGHTON MIDCONTINENT DIVISION ONE ENERGY SQ, STE 400 4925 GREENVILLE AVE DALLAS TX 75206-4083 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 e tit 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 ENERGY GRAPHICS MARTY LINGNER 1600 SMITH ST, STE 4900 HOUSTON TX 77002 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 GREENSPOINT DR HOUSTON TX 77060-1991 e e 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 MARATHON OIL CO GEORGE ROTHSCHILD JR RM 2537 POBOX 4813 HOUSTON TX 77210 EXXON EXPLOR CO LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON TX 77210-4778 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 e 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 UNION TEXAS PETR ALASKA W ALLEN HUCKABAY POBOX 2120 HOUSTON TX 77252 e UNION TEXAS PETR ALASKA CORP MANAGER-WORLDWIDE BUSINESS DEVELOP. STEVEN R FLY POBOX 2120 HOUSTON TX 77252-2120 UNION TEXAS PETROLEUM TECHNICAL SERVICES JIM E. STEPINSKI, MANAGER POBOX 2120 HOUSTON TX 77252-2120 EXXON CO USA G T THERIOT RM 3052 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 JOE VOELKER 6330 W LP S RM 492 BELLAIRE TX 77401 e e EXXON CO USA RESERVES COORD RM 1967 POBOX 2180 HOUSTON TX 77252-2180 EXXON CO USA GARY M ROBERTS RM 3039 POBOX 2180 HOUSTON TX 77252-2180 CHEVRON CHEM CO LIBRARY & INFO CTR POBOX 2100 HOUSTON TX 77252-9987 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 BELLAIRETX 77401 TEXACO INC R EWING CLEMONS POBOX 430 BELLAIRE TX 77402-0430 INTL OIL SCOUTS MASON MAP SERV INC POBOX 338 AUSTIN TX 78767 DIANE SUCHOMEL 10507D W MAPLEWOOD DR LITTLETON CO 80127 AMOCO PROD CO C A WOOD RM 2194 POBOX 800 DENVER CO 80201-0800 C & R INDUSTRIES, INC. KURT SALTSGAVER 1801 BROADWAY STE 1205 DENVER CO 80202 . 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 AMOCO PROD CO LIBRARY RM 1770 JILL MALLY 1670 BROADWAY DENVER CO 80202 JERRY HODGDEN GEOL 408 18TH ST GOLDEN CO 80401 · NRG ASSOC RICHARD NEHRING POBOX 1655 COLORADO SPRINGS CO 80901-1655 EG&G IDAHO INC CHARLES P THOMAS POBOX 1625 IDAHO FALLS ID 83415-2213 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 e RUBICON PETROLEUM, LLC BRUCE I CLARDY SIX PINE ROAD COLORADO SPRINGS CO 80906 JOHN A LEVORSEN 200 N 3RD ST #1202 BOISE ID 83702 TAHOMA RESOURCES GARY PLAYER 1671 WEST 546 S CEDER CITY UT 84720 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 ANTONIO MADRID POBOX 94625 PASADENA CA 91109 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 TEXACO INC PORTFOLIO TEAM MANAGER R W HILL POBOX 5197X BAKERSFIELD CA 93388 SHIELDS LIBRARY GOVT DOCS DEPT UNIV OF CALIF DAVIS CA 95616 . e ORO NEGRO, INC. 9510 OWENSMOUTH, #7 CHATSWORTH CA 91311 76 PRODUCTS COMPANY CHARLES BURRUSS RM 11-767 555 ANTON COSTA MESA CA 92626 WATTY STRICKLAND 1801 BLOSSOM CREST ST BAKERSFIELD CA 93312-9286 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 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 DUSTY RHODES 229 WHITNEY RD 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 . e US EPA REGION 10 LAURIE MANN OW-130 1200 SIXTH AVE SEATTLE WA 98101 PATTI SAUNDERS 1233 W 11TH AV ANCHORAGE AK 99501 DEPT OF ENVIRON CONSERV PIPELINE CORRIDOR REG OFC PAMELA GREFSRUD 411 W 4TH AVE 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 STATE PIPELINE OFFICE LIBRARY KATE MUNSON 411 W 4TH AVE, STE 2 ANCHORAGE AK 99501 TRADING BAY ENERGY CORP PAUL CRAIG 2900 BONIFACE PARKWAY #610 ANCHORAGE AK 99501 PRESTON GATES ELLIS LLP LIBRARY 420 L ST STE 400 ANCHORAGE AK 99501-1937 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 e e 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 ALASKA DEPT OF LAW ROBERT E MINTZ ASST ATTY GEN 1031 W 4TH AV STE 200 ANCHORAGE AK 99501-1994 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 e N - I TUBULARS INC 3301 C STREET STE 209 ANCHORAGE AK 99503 ALASKA OIL & GAS ASSOC JUDY BRADY 121 W FIREWEED LN STE 207 ANCHORAGE AK 99503-2035 AK JOURNAL OF COMMERCE OIL & INDUSTRY NEWS ROSE RAGSDALE 4220 B STREET STE #210 ANCHORAGE AK 99503-5911 DEFT OF NATURAL RESOURCES DIV OIL & GAS WILLIAM VAN DYKE 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEFT OF NATURAL RESOURCES DIV OF OIL & GAS JAMES B HAYNES NATURAL RESRCE MGR 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 e WEBB'S BUSINESS CONSULTING SERVICES BILL WEBB 1113 W. 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SNEA(P) DISTR FRANCE/EUROPE DU SUD/AMERIQUE TOUR ELF CEDEX 45 992078 PARIS LA DEFE FRANCE #1 ARCO Alaska, Inc. . Post Office Box I 00360 Anchorage Alaska 99510-0360 Telephone 907 276 1215 October 9, 1998 . ~~ ~~ Mr. D.W. Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 RE: Alpine Pool Rules Dear Mr. Johnston: ARCO Alaska, Inc. (ARCO), as an owner and the operator of the Alpine Pool, requests that the Alaska Oil and Gas Conservation Commission issue preliminary pool rules for the Alpine Development Project as authorized by 20 AAC 25.520. An order at this time will enhance Commission understanding of proposed drilling activities, which are beginning over a year in advance of field start-up. 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 November 10, 1998. ARCO proposes to continue development drilling by operating under Title 20, Chapter 25 regulations; however, clarification and some exceptions are requested to those general regulations. A few of the more important issues to address include: . well spacing, · drilling and completion practices, · batch drilling practices, 0 R 1 G 1 N A L . and annular injection. Attached are six copies of the application package, which includes the proposed rules, supporting prefiled testimony, and exhibits. Previously the Commission was supplied a copy of the application for injection of exempt wastes through Class I disposal wells. These wells would be completed in the Sag River-Ivishak formations below 8,650 feet. That package included data substantiating that no Underground Sources of Drinking Water (USDW's) exist within the unit boundary. An aquifer exemption was requested for all aquifers below the base of the permafrost. Please let me know the hearing date and place after they are set. Also, if you would like any additional information to be presented in advance of or at the hearing, please contact Mike Erwin at 265-1478 or me. 5J/ ? Mark Ireland (~ RECEIVED !.~~ ,. v·, -AI" 1998 AIftb«a Oil & Gas Cons. Comnùssion Anchorage ARCO Alaska, Inc. is a Subsidiary of Allantic Richfield Company AR3B-6003-C . . 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 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 Alpine File . . Alpine Pool Rules ARCO Alaska, Ine Anadarko Petroleum Corporation Union Texas Petroleum, LLC OR\G\NAL Draft October 8,1998 e e Table of Contents Page I. Introduction 3 II. Geology 4 III. Reservoir 6 IV. Reservoir Development 7 V. Drilling 9 VI. Well Operations 15 VII. Facilities 18 VIII. Summary of Testimony 22 IX. Proposed Alpine Pool Rules 23 Exhibits 26 2 e e I. Introduction This hearing has been scheduled in accordance with 20 AAC 25.540 with a public notice period started on October _, 1998. The purpose of this hearing is to present testimony supporting classification of the Alpine oil accumulation as an oil pool and establish pool rules for development of said oil pool pursuant to 20 AAC 25.520. ARCO Alaska, Inc is presenting testimony today as Operator, on behalf of the Working Interest Owners (WIOs) of the Alpine oil accumulation. The scope of this testimony includes a discussion of geological and reservoir properties, as they are currently understood, and ARCO's plans for reservoir development and surveillance, well planning, facilities installation and project scheduling. This testimony will enable the Commission to establish rules that will allow economical development of resources within the Alpine Oil Pool. Development drilling is scheduled to commence during the first quarter of 1999 with production beginning June 2000. The Alpine Plan of Development will be delivered in accordance with 20 AAC 25.517, and will be released to the AOGCC and other stakeholders prior to field start-up. The properties to be developed (i.e., the Alpine Oil Pool) are leased from the State of Alaska and the Arctic Slope Regional Corporation. The Working Interest Owners are ARCO Alaska, Inc, Anadarko Petroleum Corporation and Union Texas Alaska, LLC. The Alpine Oil Pool is located within the present boundaries of the Colville River Unit. The Alpine Oil Pool WIOs have cross-aligned their interests throughout the Alpine Oil Pool. ARCO, on behalf of the Alpine Oil Pool WIOs, will file an application requesting the Department of Natural Resources to approve an Alpine Participating Area, which will include the Alpine Oil Pool. Said application will also include plans of development and operations for the Alpine Participating Area, including the Alpine Oil Pool. ARCO will file a copy of the Alpine Participating Area application with the Alaska Oil and Gas Commission. 3 · e II. Geology Introduction This section provides geologic data and interpretation in support of ARCO's proposed Alpine Oil Pool. Location The Alpine Oil Pool is located approximately 20 miles west of the Kuparuk River Field 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. Strati2raphy 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 3). The uppermost Alpine sandstone has the best reservoir properties of the three Jurassic sands. 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 2380 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 0.1 to 160 millidarcies. The best quality sandstones are coarser grained with low matrix content. Thin discontinuous sands with overall poor reservoir quality (see Exhibit 3) characterize the Lower Cretaceous Kuparuk Sandstone in the Alpine Field area. The Fiord 1, 2 miles north of the Alpine Field, penetrated 20 feet of Kuparuk net pay and tested ±1000 BOPD of 31.6° API gravity oil. Clastics in the Albian Torok Formation include thin-bedded turbidite sandstones with generally poor reservoir quality (Exhibit 3). Interbedded sandstone and mudstone packages up to 100 feet thick are complexly distributed across the Alpine FieI1i'~~'" \. . LJns. Gmr:mISSio¡ Anchorar¡:;; \.< 4 · e A2;e 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 6876 and 6976 measured depth in the Bergschrund 1 well (Exhibit 4) 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 Alpine Field. 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 of the Kingak and Miluveach formations. Hydrocarbon distribution is controlled by the distribution of reservoir quality sandstones. No water or gas cap has been encountered 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 Field area are north- northwest trending, down to the west, normal faults. At the Alpine level, most of the faults have small throws, generally less than 25 feet. 5 e e III. Reservoir Introduction This section will summarize reservoir properties. Core data provides the foundation for much of the rock property information presented in this section. Whole cores were collected from the Alpine #1, Neve #1, and Nuiqsut #1 wells. In addition rotary sidewall cores were obtained from the Alpine #1, Alpine #3, Bergschrund #1, Bergschrund #2A, and Fiord #3. A laboratory fluid study performed on subsurface oil samples, obtained while flow testing the Bergschrund #1 and Alpine #IB wells, provide the basis for the reservoir fluid description. Porosity. Permeability and Water Saturation The Alpine sandstone is very fine-grained with core measured porosity ranging from 15- 20% and averaging 19%. It has air permeability ranging from 1 md to 150 md, averaging 15 md. The average core based water saturation (after correcting for invasion) was measured at 20%. Net Pay Determination A porosity cutoff of 15% and a water saturation cutoff of 50% define net pay. Reservoir Fluids and PVT Properties The initial reservoir pressure of the Alpine sandstone is 3175 psig at 6864' true vertical depth subsea (TVDSS). For future reference, this equates to 3215 psig at 7000' TVDSS. Average reservoir temperature is 160 degrees F. Well test pressures, RFT pressures, and oil sample fingerprinting indicate the Alpine accumulation is in continuous hydraulic communication. Bottomhole reservoir fluid samples were taken in Bergschrund #1 and Alpine #1B. Analyses of these samples indicate the reservoir is undersaturated with a bubble point pressure of 2454 psig. At initial reservoir pressure, the formation volume factor is 1.469 RB/STB based on constant composition expansion experiments. Solution GaR under these conditions is 850 SCF/STB. Reservoir fluid density at the bubble point pressure is 0.6786 gm/cc. Oil viscosity is 0.46 cp at reservoir conditions. Oil gravity, as determined during the actual testing, is 40 degrees API. Orh!inal Oil-in-Place (OOIP) The stock tank OOIP volumetric estimates for the Alpine Oil Pool range from 900 to 1100 MMSTB, with an expected value of about 1000 MMSTB. Net pay maps were developed from 3-D seismic and well control data. Water saturation and porosity maps are based on interpolation of well properties. 6 e e IV. Reservoir Development Introduction This portion of the testimony includes a discussion of the recovery process selection, reservoir mechanisms, development strategies, and future optimization plans for the Alpine Reservoir. Recovery Process Selection To evaluate the performance of the Alpine reservoir, a 3-D compositional model was constructed covering the entire Alpine Field. Lean gas injection, miscible gas injection and waterflood development scenarios were evaluated with this model. Waterflooding with seawater was the recovery method selected. Additionally, waterflooding could be followed later with either lean gas or miscible gas injection to further improve ultimate recovery. The major uncertainty in the waterflood case is the ability to inject water at acceptable rates. In the event that water injectivity is below expectations, Alpine would be converted from waterflood to gas flood. Recovery Mechanism Fine grid models were run to develop a "truth case" for calibrating the full field models. The base case assumed primary recovery from an undersaturated oil reservoir. This model showed that the waterflood recovery process had excellent volumetric sweep efficiency and more than insignificant additional recovery over primary. The low degree of permeability variation, the favorable water to oil mobility ratio of 0.10 and the relatively thin reservoir section with no identifiable continuous permeability barriers all contribute to high volumetric sweep efficiency. Current Development Approach The scope of the current Alpine development project is broken into two Phases. Phase 1 provides for 50 new wells (this includes the two existing wells drilled in 1998) and Phase 2 provides for an additional 42 wells with a total of 92 wells. Total development includes 32 horizontal wells and 60 vertical wells. Horizontal wells are on 275-acre spacing and vertical wells are on 160-acre spacing. Wells are drilled out to a 200 md-ft cutoff, which is assumed to be the economic limit for Alpine wells. Potential Revised Development Plans The Alpine Owners are evaluating a revised development plan to change the recovery process and tighten the well spacing. The current recovery process is waterflood in the center of the field and gas re-injection around the periphery of the field. The revised development plan would be miscible-water-alternating-gas (MW AG) throughout the field. Gas will be enriched to become miscible with the reservoir oil. The currently planned well spacing is 275 acres in the center ofthe field and 160 acres around the field periphery. The revised well spacing would include horizontal wells on 135 acre spacing 7 e e throughout the field, in order to take full advantage of the MW AG process. The revised development plan calls for up to 140 wells. Future Optimization Optimizing field development will be an ongoing process requiring additional field data, laboratory studies and reservoir modeling. Current studies are focused on updating the full field model with a new reservoir description, new relative permeability information, and a new equation of state characterization. The effective length and skin of the model wells is being tuned based on well test data. Simulation studies to determine the incremental recovery from MW AG are also underway. We have plans to test extended length horizontal wells and multilateral wells to reduce the number of wells required to access all planned bottomhole locations. Producin2 Gas-Oil-Ratio Expectations. Because the Alpine facilities will be re-injecting produced gas, the GOR is expected to rise above solution GaR in some wells. The breakthrough of re-injected gas may cause gas-oil ratios of some producing wells to exceed limits set forth in 20 AAC 25.240(b). However, the Alpine Oil Pool average reservoir pressure will be maintained above the bubble point pressure. For this reason we request exemption from this rule. Well Conversion Strate2Y Alpine development is designed to provide a 1: 1 injector/producer ratio. At startup of the production facilities, we expect to have a limited number of producers available. To briefly increase production at a time when the water supply line to Kuparuk is not expected to be available, pre-production of injection wells may be appropriate. After a short pre-production period, these pre-produced injectors would be placed in injection service. 8 e e V. Drilling Introduction This portion of testimony will include a description of our logging, drilling, casing, cementing, well suspension, annular injection and blow-out prevention equipment (BOPE) testing plans. Directional Drillinsæ; Continuous MWD surveys will be used as they have proven to be effective in surveying horizontal wells on the North Slope. The detailed reporting and plotting for direction ally drilled wells as described in 20 AAC 25.050(b) should be waived for the Alpine Oil Pool. Current guidelines call for extensive data packages in the Application for Drilling Permit on all wells located within 200 feet of a well to be directionally drilled. As essentially all wells in the Alpine Oil Pool will be directionally drilled from wellheads spaced on 10-foot centers, this places an unnecessary burden on both the Operator and Commission. Losæ;sdnsæ; Operations The minimum log suite planned for Alpine includes resistivity and gamma ray logs in the productive intervals. These logs will be obtained from MWD/LWD tools positioned in the drilling BHA. At some point in the future, it is possible that Alpine wells could be drilled solely using rate of penetration (RaP) as well as other drilling indicators to locate the pay zones. In keeping with Commission practice, at least one (1) well on each drilling pad will be logged from surface to TD with GR/Resistivity/Neutron tools. As the first well on pad, CDl-22 was successfully investigated from surface to the Alpine Oil Pool with a suite of gamma ray/resistivity/neutronJdensity logs. However, this did not occur while drilling CD2-35 due to wellbore conditions. The next well drilled on this pad (CD-2) will be logged with gamma ray/resistivity/neutron/density tools from the conductor casing to the Alpine Oil Pool. Similar log investigation of formations shallower than the Alpine Oil Pool in additional wells on these same pads will be performed at Operator discretion. DrillinWW ell Desisæ;n The Alpine Oil Pool will be accessed from wells direction ally drilled from one of two gravel pads utilizing drilling procedures, well designs, and casing and cementing programs consistent with current practices in other North Slope Fields. Alpine will be developed utilizing the latest in directional drilling and extended reach techniques. The following paragraphs will preview an Alpine drilling proposal for both producing and injection wells. ,..,' r t' rIVED 9 A¡é!~;ì« . "ij9 Luns. CommissiOi ".~raf!b e e 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. Permafrost depth in the Alpine Field varies from 750' to approximately 900' TVDSS. This casing setting depth provides sufficient depth for kick tolerance, yet shallow enough to initiate build sections for high departure wells. 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 Alpine 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 utilizing the latest directional techniques from surface casing, encountering the top of the Alpine at 50-70 degree inclination. Production casing will be set close to horizontal and cemented within the Alpine Sands. 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 to achieve a minimum test of 1 ppg equivalent mud weight (EMW) above reservoir pressure. Note that the Alpine reservoir fracture gradient (20 AAC 25.030(d)(2)(D)) will not be reached to minimize formation damage. Production hole will be drilled beyond the casing shoe horizontally in 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 intervals may receive slotted liners. 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, the production casing will be cemented across and 500 feet measured depth or more above the Alpine Sand. An example would be any extended reach S- shaped wells that encounter the Alpine Sands at inclinations below 60 degrees. These wells would follow the cementing and testing conventions above. Due to the casing design employed at Alpine, exception to 20 AAC 25.030(g)(3) is requested for injection wells. We request all casing 7" and smaller, rather than 9-5/8"and smaller, be inspected with a cement bond log. The 9-5/8" surface casing will be pressure tested only. 10 e e In addition to conventional open hole and perforated completions, it is proposed that pool rules authorize the following alternative completion methods a) Slotted liners, wire-wrapped screen liners, or combination thereof, landed inside of cased hole and which may then be gravel packed. b) Vertical or "conventional" open hole completions. Openhole completions may subsequently be completed with slotted or perforated liners, wire-wrapped screen liners, or combinations thereof, and may be gravel packed. c) Horizontal or "high angle" completions with liners, slotted or perforated liners, wire-wrapped screens, or combination thereof, landed inside the horizontal extension, and which may be cemented and perforated or gravel packed. d) Multi-lateral type completions in which more than one wellbore penetration is completed in a single well, with production gathered and routed back to a central wellbore. If the Operator desires to utilize any other casing or completion methods it shall seek administrative approval by submitting and presenting data demonstrating that such alternatives are based on sound engineering principles. Batch Drilling Plans To expedite the drilling process and minimize pad storage requirements the drilling schedule will follow a "batch drilling" schedule. For example, 6 wells may be drilled to surface casing point and suspended while the rig moves to the next well. Before the end of the drilling season, each of the 6 wells will be drilled to completion. This process will be described in the initial Permit to Drill, Form 10-401. The following details a typical batch drilling suspension procedure. a) Wells suspended after setting surface casing will be left as follows; 1) Surface casing shoes will not be drilled out. 2) Cement plugs will be left inside the surface casing a minimum of 50 feet above the shoe. 3) Wellbores will be displaced to water and freeze protected. 4) Well bores will be pressure tested to verify integrity of the cement plug and casing. Notice of the test will be given to the Commission in time such that a representative of the Commission may be present to witness the work. 5) Wellheads will be capped with a dry hole valve. b) Wells suspended after setting production casing will be left as follows; 1) Production casing shoes will not be drilled out. 2) Cement plugs will be left inside the surface casing a minimum of 50 feet above the shoe. 3) Wellbores will be displaced to water and freeze protected. 4) Wellbores will be pressure tested to verify integrity of the cement plug and casing. Notice of the test will be given to the Commission in time such 11 e e that a representative of the Commission may be present to witness the work. 5) Wellheads will be capped with a dry hole valve. The AOGCC will be notified of rig moves. Changes to the approved drilling permit will be communicated to the AOGCC on Form 10-403 in accordance with 20 AAC 25.015. Ice roads currently provide the only available means for rig travel between the pads or other fields. With pad to pad moves limited to the winter season, the potential exists for rig moves which strand a previously "batch drilled well" on a pad for more than 12 months before it can be drilled to completion. In this event, an Application for Sundry Approvals, Form 10-403, will be filed with the Commission in accordance with 20 AAC 25.015. Blowout Prevention It is proposed that the rule for blowout prevention in the Alpine Oil Pool be written according to the provisions established in Regulation 20 ACC 25.035 (Secondary Well Control: Blowout Prevention Equipment (BOPE) Requirements) of the AOGCC regulations with one exception to 20 AAC 25.035(a)(7)(a). Operator proposes that BOPE and annular preventer tests shall be made when the BOPE is installed or changed, and at least once every two (2) weeks after that. This is consistent with the recent revision to the u.s. Department of Interior Mineral Management Service (MMS) regulations concerning BOPE testing on OCS operations. See 63 FR 29604-608, June 1, 1998. Test results will be recorded as part of the daily record in accordance with 20 AAC 25.070(a)(1). Except as modified by the AOGCC regulations, blowout prevention equipment and its use will be in accordance with API Recommended Practice 53 for blowout prevention systems. Drillin2; Fluids The drilling fluid program designed for Alpine wells will be prepared and implemented in full compliance with 20 AAC 25.033 in the AOGCC regulations. Formation pressures for the strata to be penetrated are well known and documented based on numerous Colville Delta wells, which have already been drilled through the Alpine interval. Wellhead and Production Tree Desi2;n The Alpine wellheads and trees are designed for the operating conditions expected at Alpine. The "horizontal wellheads" are very similar to those currently being used in the West Sak Field. Horizontal trees route oil and gas flow through a port in the side of the tubing hanger, and then through a wing valve to the production flow line. This design reduces the height of the wellhead and allows the well to be worked over without removing the flow line. All wellhead and production tree equipment carries the API monogram and meets or exceeds API RP 14C. 12 e e Annular Disposal of Drillin2 Wastes Annular disposal of drilling waste is proposed during Alpine drilling and completion operations. It is requested that a blanket permit be approved for pumping fluids down the surface casing annulus of Alpine wells as a result of drilling operations per 20 AAC 25.080. Any zones containing significant hydrocarbons will be isolated prior to initiating any annular pumping. There are no underground sources of drinking water (USDW's) in the area, or potable/industrial water wells within one (1) mile of the Alpine Oil Pool. Formation markers are shown in Exhibit 7. The only publicly recorded wells within 1/4 mile of disposal operations will be other Alpine Oil Pool wells. Incidental fluids from drilling operations will be pumped down the annulus of wells in the Alpine field. Disposal will take place in wells on the same pad as the waste generating operation. Please note that cement rinseate is proposed to be injected down an open annulus. The surface/production casing annulus will be left with a non-freezing fluid during extended idle periods. The surface/production casing annulus will be filled with diesel after setting the production casing. When isolation is required in accordance with regulations concerning standoff from significant hydrocarbons, and the surface shoe is within 200' TVDSS of the top of the hydrocarbons, the annulus will be sealed with cement from the surface shoe to the base of the permafrost with pack fluid or diesel. If the hydrocarbons are well below the shoe, then sufficient cement volume will be pumped to cover the formation. Surface casing will be set at approximately 2350' TVDSS near the Cretaceous C-30 marker (Exhibit 7). The annular disposal interval consists of 250' -300' of unconsolidated sandstone and mudstone. Approximately 1100' of barrier mudstone and siltstone separates the receiving interval from the overlying West Sak sands. The maximum volume of fluids pumped down the annulus of any well will not exceed 35,000 barrels without AOGCC permission. Fluid densities will range from 6.8 ppg for diesel to a maximum of 12.0 ppg for drilling mud and cuttings. Using 12 ppg fluid and a maximum pumping pressure of 1500 psig, the maximum pressure at the surface casing shoe is estimated by; Maximum Shoe Pressure = 12.0 ppg x 0.052 psi/ft x Surface Casing Shoe Depth + 1514.7 psia Maximum Shoe Pressure = 2981 psia (assuming Surface Casing Shoe Depth is 2350' TVDSS) The surface and production casing strings exposed to the annular pumping operations are determined to have sufficient strength by using 85% collapse and burst ratings as listed below. aD (in.) 9-5/8 7 Weight (lb/ft) 36 26 Grade Range Connection J-55 3 BTC L-80 3 BTC-Mod Collapse (psia) 2020 5410 Collapse x85% 1717 4599 Burst (psia) 3520 7240 Burst x85% 2992 6154 Based on formation strength analysis the expected surface pressure to inject fluid would be 284 psig for a 12 ppg fluid. The minimum in situ horizontal stress is approximately 1750 psig. 13 e e Surface injection pressure = 1750 psig - (12.0 ppg x 0.052 psi/ft x 2350' TVDSS) = 284 psig Fluids to be disposed of in a surface casing annulus will be limited to drilling fluids and wastes associated with drilling wells as defined in 20 AAC 25.080(h). It is requested that cement rinseate be determined as drilling waste under 20 AAC 25.080(h)(3). 14 e e VI. Well Operations Well Desi2n and Completions Typical completions will utilize 3-112 and 4-1/2" tubing to exploit the production potential of horizontal wells. Smaller tubing may be appropriate in the peripheral extensions of the field. Either design will be consistent with the designs popular across the North Slope, with 9-5/8"surface casing, 7" production casing, and 4-112" or 3-112" tubing. A single packer set near the production casing shoe will provide pressure isolation for the tubing casing annulus. All producing wells will be equipped with gas lift mandrels. Wells with liners in the horizontal segments will not utilize packers. The tubing string will utilize sliding seals which seal into a polished bore in the liner hanger. All completions will target reserves in the Alpine Oil Pool. Wellbore departure will reach laterally as far as 15,000 ft. from the current pad locations. High departure and extended horizontal completions will push measured depths to the 21,000-ft. range. Sidetracks Openhole completions provide an ideal platform for future sidetracks. Pressure communication and waterflood breakthrough will delineate directional permeability, channels or thief intervals. Once identified, openhole completions can be plugged back and redrilled to improve sweep and enhance recovery. At this time we anticipate sidetracks which preserve overall line drive patterns with parallel laterals. In addition to pattern modification, sidetracks could increase water injection, sidestep faulting or penetrate bypassed oil. Sidetracks within the Alpine Oil Pool can be expected to expose producing reservoir pay within 500' of established well bores in the Alpine Oil Pool. For this reason the Alpine Oil Pool is requesting a waiver on spacing limitations, with the exception of a 500-foot perimeter around the pool. Artificial Lift Gas lift will be employed at Alpine as the sole artificial lift mechanism to optimize reservoir pressure drawdown, provide lift for long reach horizontal wells, and enhance production rates at the increased watercuts anticipated following waterftood response. Reservoir Surveillance Pressure monitoring is a key component of the long term Alpine Oil Pool surveillance. Static bottomhole pressure surveys will be conducted in all new injection wells prior to initiating injection. Static surveys will similarly be performed in certain production wells. For annual pressure surveillance, a minimum of six (6) pressure surveys will be conducted annually in the field, concentrating on injection wells. Due to the relatively small number of pressure surveys, an annual, rather than monthly, report will be filed F F' ED 15 Aifj;~i(ê~ . !'i'~ lCJí1S. ~()f¡ e e with the Commission. Since lengthy horizontal wells require extended shut-in periods, often months long, to achieve stabilized bottomhole pressures alternative pressure survey methods will be required. Alternative allowable survey techniques include openhole wireline RFf measurements, cased hole pressure buildups with bottomhole pressure measurement, injector surface pressure fall-off, static pressure surveys following extended shut-in periods, or bottom hole pressures calculated from well head pressure and fluid levels in the tubing of a stabilized shut-in injector. Pressure build-up tests will be extrapolated to estimate static reservoir pressure while injection wells may become the preferred source for static pressure surveys. While the field extends between 6,800 TVDSS and 7,700 TVDSS, a representative common datum for reporting should be 7,000 feet TVDSS. Additional surveillance logging will include spinner surveys to monitor effective producing or injecting well length. This will be accomplished with coil tubing conveyed memory logging tools. Spinner logging will provide information concerning effective producing length in the horizontal sections often leading to stimulation and remedial wellwork. Additionally, waterflood surveillance will be enhanced through understanding fluid migration patterns, identification of unswept target intervals and lenses and permeability trends. W orkover Operations Well work operations in the Alpine Field will include routine mechanical integrity tests of each well bore and artificial lift maintenance. Unlike more typical multi-zone or multi- layer fields on the North Slope, the Alpine Oil Pool represents a single hydrocarbon accumulation. Production from a single pool with openhole completions minimizes profile modifications, perforating and plugback operations. With a remote location and limited access for heavy equipment, major work activities including fracture or acid stimulation and tubing or casing repairs will likely be performed during winter utilizing ice road access. Due to the routine well work nature we are requesting a waiver to the requirements of 20 AAC 25.280(a). This is intended to reduce the paperwork burden on both the AOGCC and the Alpine Oil Pool Operator. Stimulation Methods Stimulation techniques may be used at some point to enhance productivity of the Alpine reservoir. Stimulation to remove drilling induced formation damage and enhance near wellbore flow characteristics will be performed to increase the commercial flow rates in this reservoir. Propped hydraulic fractures appear to be the most promising producer stimulation technique available at present. Well bore trajectories, cementing programs, and tubulars will be designed to accommodate hydraulic fracture stimulation techniques. Subsurface Safety Valves Consistent with statewide AOGCC regulations (20 AAC 25.265) for onshore fields, sub- surface safety valves (SSSVs) will only be used in the Alpine Oil Pool based on Operator discretion. Producing wells will have either a tubing profile nipple or tubing retrievable SSSV installed below the permafrost at approximately 1,000' TVDSS. Injection wells 16 e e will be equipped with a single tubing profile nipple set below the permafrost at approximately 1,000 ft. for anticipated installation of a slickline conveyed SSSV. In the event SSSV s are installed, periodic inspections and testing will be conducted following notification of the Commission. Surface Safety Valves All wells capable of unassisted flow of hydrocarbons will be equipped with fail-safe automatic surface safety valves (SSVs). They have been specifically designed to accommodate the wellhead and casing requirements of Alpine wells, and will be located in the typical "wing" position. These devices will be pressure actuated and are designed to isolate well fluids upstream of the SSV whenever pressure limits are exceeded. Additionally, injection well flowlines will be equipped with check valves in the surface pIpmg. Periodic inspections and testing, not to exceed annually, will be conducted following notification of the Commission. 17 e e VII. Facilities Introduction The Alpine field is located approximately 40 miles west of the Kuparuk base camp and is a completely independent operation. The field is being developed with two main gravel pads connected by a 3-mile long road. The first mile of the road also serves as a runway for air support of the operation. The eastern pad is roughly 2600 feet long and varies in width from 400 to 750 feet. This pad has several discreet parts. The central processing facility (CPF) is located on this pad as well as the field infrastructure including the camp, shops, and warehouse. At the western end of this main pad is the first drill site (CD-I) designed for 40 wells and a large storage pad for storing drilling supplies. Three miles to the west is the second drill site (CD-2). This pad is 500 feet by 800 feet and is designed for 50-60 wells. It also includes a smaller section for storing drilling material. The road connecting the two pads is designed to allow the rig to move back and forth between the pads throughout most of the year. The Alpine field does not have a year round road connecting to the existing North Slope infrastructure. Ice roads will be built in the winter to bring in supplies. During the 8-9 months per year when ice roads cannot be utilized, Alpine will be dependent on air support for all supplies. Infrastructure Alpine is being built as a stand-alone grass roots installation. Therefore the entire infrastructure required for operating and maintaining an oil field on the North Slope of Alaska is included in the design. Primary features include: 1. A 140 bed permanent camp with kitchen, dining room, recreation facilities. 2. All utilities required for running the camp including potable water treating, wasting water treating, solids incineration, and composting for food wastes. 3. Small warehouse for onsite storage of critical materials. 4. Shops for production and drilling. 5. Wash bay for cleaning all equipment and properly handling all wash water effluent. 6. Fine Water Mist system for fire protection of the infrastructure and the process plant. 7. Telecommunications equipment required for all phones, radios, and computer connections within the field and back to Anchorage. 8. 5,000-ft runway for handling aircraft up to and including C-130 Hercules aircraft. 9. Class-l waste disposal well. 18 e e Drill Site Facilities The CD-l drill site is adjacent to the processing plant. This drill site is designed for 40 wells equally split between producers and injectors. Wells are individually piped into manifold buildings were the production fluids are commingled for transport through a short pipeline into the processing plant. A separate test header is connected to each well slot so that produced fluids can be individually routed through a test separator in the main plant. This test separator will provide two-phase separation and measure flow rates of the gas and liquid phases. The liquid stream will pass through a Phase Dynamics meter to determine the oil/water split of the liquid. The manifold building will also have water and gas injection headers bringing high- pressure fluids from the plant to the drill site for injection. Each injection well will be piped to receive either water or gas depending on the reservoir development plan. CD-2 is located approximately 3 miles west of the CD-l pad. This pad is designed to have 50-60 wells equally split between producers and injectors. The manifold facilities are identical to those on CD-l with production being commingled into a 3-mile long 20" pipeline back to the processing plant. The multi-phase test meter for CD-2 production CD-2 is located on the drillsite. This two-phase separator and meter measures oil, gas, and water composition of the well fluid by the same means as the separator for CD-I. Central Processine Facility The Central Processing Facility (CPF) takes the well production and separates fluids into oil, gas, and water streams. Oil is sold through a sales meter skid and pumped through a 14" pipeline to Kuparuk's CPF-2 where it connects into the existing Kuparuk pipeline system. Gas is dehydrated and compressed for reinjection into the Alpine reservoir with a small portion of the gas used as fuel for the facility or gas supply to Nuiqsut. The separation train consists of three primary process vessels, including the Inlet Separator, Low Pressure Separator, and Dehydrator. These three vessels remove gas and water from the oil to produce pipeline quality crude oil. This section of the plant contains heat exchangers to enhance water separation and control sales oil vapor pressure, heat exchangers to cool sales oil, and pumps for transferring sales oil from Alpine to Kuparuk. A sales meter skid, with a ball type meter prover conforming to API Manual of Petroleum Measurement Standards, measures the oil sales volume pumped into the pipeline. The oil section of the plant and pipeline are designed for a nominal rate of 90,000 BOPD. In the early years of operation produced water rates are expected to be low. Produced water will be separated from the oil stream and commingled with other non-hazardous fluids for injection into a Class 1 Industrial Waste well. Later in the life of the field, as water production rates increase, a produced water handling system will be installed. Formation water will then be commingled with waterftood fluids and reinjected into the Alpine reservoir for pressure maintenance and waterftood support. Gas separated from oil in the separation train is processed and compressed for reinjection into the reservoir. There are two compression systems in the Alpine CPF. The low- 19 e e pressure compressor is an electric driven centrifugal compressor, boosting gas in the plant up to 150 psig. The injection compressor is a three stage centrifugal compressor driven by a GE Frame 5 gas turbine. This compression train boosts inlet gas from 150 psig to 4500 psig for reinjection into the reservoir and for use as artificial lift gas on the production wells. Between the first and second stages of this compressor is a dehydration system for removing water from the gas. The dehydration system uses Triethylene Glycol (TEG) and is similar in design to other North Slope dehydration systems. Approximately 15-18 MMSCFD of dry fuel gas is then available to both Alpine and the neighboring village of Nuiqsut. With Unit approval for a miscible gas project, fuel gas would be sent through a chiller to remove natural gas liquids which could be reinjected into the high pressure gas stream creating a Miscible Injectant (MI) for injection into the reservoir. The CPF also has two seawater injection pumps for injecting seawater into the reservoir for pressure maintenance and waterflood. A 12" seawater pipeline brings treated seawater from the Kuparuk STP to Alpine. Alpine pumps then provide sufficient pressure for injection into the reservoir. The CPF contains the utility systems required to operate a North Slope oil field. Electricity is generated using a General Electric Frame 5 gas turbine as the primary generator. A General Electric PGT 10+ turbine and two internal combustion engines drive backup power generators. Other utility systems include instrument air, nitrogen, plant air, cooling glycol, and heating glycol. Diesel fuel will be provided through a 2-3/8" pipeline from Kuparuk. Production Allocation Production will be allocated to producing wells based on the actual plant oil sales volume and well tests on individual producing wells. All the wells are connected to a test header system, which go to a test meter on CD-2 pad or a test separator in the CPF. Each producing well will be tested at least quarterly to ensure accurate allocation of the produced fluids. Quarterly well testing is requested due to the high concentration of wells per pad and test facility. The most rapid change in well performance is expected during the first year, and monthly tests during that time will identify significant production declines. The control system in the Alpine field will continuously gather operating data from the wells and the test separators. The exact procedure for allocating the production is not detailed here but the following points will be followed: 1. All wells will be periodically tested. 2. The stabilization and test duration of each test will be optimized by the Operator to obtain a representative test. 3. Well and field operating condition information required for the construction of a field production history will be maintained. 20 e . 4. Major test separator meters and major gas system meters will be installed and maintained according to industry recommended practices or standards. 5. The Operator will maintain records that permit verification of the satisfactory execution of the approved production allocation methodologies. 21 . . VIII. Summary of Testimony As previously discussed today, oil and gas was initially tested from the Alpine Reservoir in the Bergschrund No.1 in April 1994. Since the initial field discovery, eight additional penetrations of the reservoir have successfully delineated the field. Earlier this year, ARCO successfully drilled the first two horizontal wells. Plans are moving forward to initiate a multi-year development drilling program beginning this winter. We are requesting pool rules at this time to provide flexibility moving forward with the development phase. Looking ahead to field start-up in June of 2000, these pool rules provide a basis for ongoing operations that safely protect fresh waters, maximize recovery of the resource, minimize waste and protect ownership correlative rights. Key elements of the pool rule requests include; Definition of the Alpine Oil Pool, Batch drilling procedures, ~)t ;:' \\~'~ "... fCD [:.~ V D.· . Casing and cementing procedures, Annular injection procedures, A1as1æ Db 3, {jas Gons. tomrmssiof¡ Anchorags .. and ongoing Reservoir Surveillance. Development plans call for early start-up of water injection facilities for waterflood and pressure maintenance with allowances to readily transition to enhanced oil recovery operations. Once the results of studies currently underway are finalized and understood, we will return to present testimony requesting an Area Injection Order for the Alpine Oil Pool. At that time we will review a more thorough development plan which we hope will include details of an enhanced oil recovery project for Alpine. ARCO Alaska, Inc, Anadarko Petroleum Corporation and Union Texas Alaska, LLC are committed to a safe and environmentally sound operation. The pipelines, pads, roads and infrastructure have taken years of planning to minimize environmental impacts within the Colville Delta. Our experiences operating on the North Slope have lead to development of numerous 'best practices', which are reflected in our drilling and operating plans. Alpine will be our blueprint for 21 st century North Slope field developments that maximize reserve recovery while minimizing environmental impacts. The development of Alpine, with its range of environmental and logistical opportunities creates many new challenges for the stakeholders. We look forward to working through these challenges as we develop an optimal depletion plan for the Alpine Field. Thank you for this opportunity to provide testimony today and will be available to answer any questions you may have. 22 . . IX. Proposed Alpine Oil Pool Rules The rules hereinafter set forth apply to the following described area and are referred to in the order as the affected area: Umiat Meridian Tl1N, 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. Rule 1. Field and Pool Name The field is the Alpine Field and the pool is the Alpine Oil Pool. Rule 2. Pool Definition The Alpine Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Bergschrund No.1 well between the depths of 6,876' MD and 6,976' MD. Rule 3. Well Spacin2 The requirements of 20 AAC 25.055 are waived for development wells in the Alpine Oil Pool. Development wells will be drilled initially in line drive patterns on 1,500 feet spacing between well rows. Unlimited spacing will be allowed between wellbores of adjacent wells. The reservoir shall not be exposed in any well closer than 500 feet from the boundary of the Alpine Oil Pool. Rule 4. Drillin2 and Completion Practices a) Upon drilling out no more than 50 feet of new formation within the Alpine Oil Pool, a Formation Integrity Test will be performed. Test pressures need not exceed the fracture gradient of the Alpine Oil Pool. b) Alternate casing and completion programs may be administratively approved by the Commission upon application and presentation of data which demonstrate the alternatives are appropriate, based upon sound engineering principles. c) All ram-type BOPE's, kelly valves, emergency valves and choke manifolds must be pressure tested to the rated working pressure or to the maximum surface pressure when the equipment is installed or modified, and at least once 23 e . every two (2) weeks thereafter. Test results will be recorded as per 20 AAC 25.070(a)(1). d) The detailed permitting requirements for deviated wellbores in 20 AAC 25.050(b) are waived for development wells in the Alpine Oil Pool. e) The requirements of 20 AAC 25.071(a) are waived. A complete electrical log and radioactivity log will be provided for one well on each drilling pad. Additional wells will not be logged across the full length of the well, except at Operator discretion. f) The requirements of 20 AAC 25.030(g)(3) are amended to require cement bond logs on all injection well casings smaller than 7", rather than 9-5/8". g) Disposal of drilling waste through the surface casing annular space, 20 AAC 25.080, in Alpine wells is authorized. Rule 5. Reservoir Surveillance a) Prior to sustained injection, an initial static pressure survey will be taken in each injection well. b) A minimum of six (6) pressure surveys will be taken in the Alpine Oil Pool and reported to the Commission annually. Pressure surveys taken as part of Rule 8(a) may fulfill this requirement. c) The reservoir pressure datum for reporting will be 7000 feet subsea. d) Pressure survey results will be reported to the Commission annually on form 10-412, Reservoir Pressure Report. Rule 6. W orkover Operations The requirements of 20 AAC 25.280(a) are waived for development wells in the Alpine Oil Pool. Rule 7. Automatic Shut In Equipment a) Testing of surface safety valves (SSV) will be conducted within twelve (12) month intervals. Notice of testing will be given to the Commission in time such that a representative of the Commission may be present to witness the work. b) A subsurface safety valve (SSSV), installed at Operator discretion, must be maintained in working order and is subject to performance testing comparable to the surface safety valve (SSV). Rule 8. Production Practices The requirements of 20 AAC 25.230(b) are waived allowing well tests to be conducted a minimum of every 3 months following the well's initial 12 months of production. 24 e - Rule 9. Gas-Oil Ratio Exemption Wells producing from the Alpine Oil Pool are exempt from the gas-oil limit (GaR) set forth in 20 AAC 25.240(b). Rule 10. Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend the order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. 25 e e List of Exhibits Exhibit 1 Alpine Field Location Map Exhibit 2 Alpine Oil Pool Section Boundaries Exhibit 3 Bergschrund 1 Type Log Exhibit 4 Alpine Oil Pool Type Log Exhibit 5 Top Alpine Depth Structure Map Exhibit 6 Phase 1 Development Plan Exhibit 7 Annular Injection Cross Section Exhibit 8 Alpine Producer Wellbore Schematic (openhole) Exhibit 9 Alpine Producer Wellbore Schematic (slotted liner) Exhibit 10 Alpine Injector Wellbore Schematic 26 EXHIBIT 1 ALPINE FIELD LOCATION MAP Rule 1. The field is the Alpine Field and the pool is the Alpine Oil Pool Kuukpik Unit . Kalubik 1 ~~ GÞ ~Ç¡ \JT7~£J'lA 41& Kuuk 3 ¡J 0- ílÞTex lit Ugnu 1 III Sine C 1 2A Kuparuk River Unit ND2 . Areo Colv R 1 # ,NPRÁ. ' , " , II Kookpuk 1 Tam # 1 @I #1 ~ ~ 2 Alpine Pool Section Boundaries INE 5 4 3 2 1 8 9 10 I: 4 3 2 1 6 9 10 11 12 1 11 15 18 17 13 15 16 16 14 13 !-- 19 20 21 21 22 19 23 30 29 28 21 26 28 26 11 29 27 32 { 35 2 33 34 35 ......1 RE 4E I 1121\1 R5E 3 I 2 1 6 5 4 1 2 1 6 8 10 11 12 1 8 \I 10 11 12 7 TEM HI A 31 6 -~ 1 IÄ 1 11 16 'l;~~ 18 7;~~/~~~ 30 32 ~~ 3 3BlfG 3 31 y:~A. "/ "/ / · 8 ~~~y 12/~~ Cell ~u~ 1 13 18 11 ~~~'~ /~~~~~ 18 : ~ ~ ~ ~~ . /~~V~~~rt : . 18 T nON 1 filii 14 15 14 22 23 28 ~h 1 12 P"""/'t" Colville River Umt Boundary ILJ Alpine Oil Pool Sections )1\ II;: c: J: U C ~ :::;) -I .- :E t ,... " :E u.. ~ C ð z 2 fit) I ALPINE Oil pnru B y t"t: lOG o I I t ,GR I 'I 1 ReSiStiVity~j, , I", i ! lj't ¡ ¡ ¡! ! ¡ 1¡ ¡¡ ¡! ¡ ¡, ¡ 1 ¡ ¡ ~ I i ;-«~I [.11 I II1I T<1 i i Iii 1&, I III' ~,J-r I' :::...,. Ii' I ! ! i : i! 6860 <-- ¡ \ V! í ¡ ~ \ ! ì i i ì I ì I I i I ¡ I _i...-'-¡"""'" -> I I ( .- o o A. . .6 A. :ë I . f !) ( 6880 ¡ I I I ì ì I I i I I 6900 I i I I I i I , , ¡ I ! 6920 6940 I I i . i I I I I ¡ UI!ì í I I I I 6960 k__þ :'/--1 1> ~ i Þ I I ~¡ I ' ¡ i I I ! i , \ I I I rrl ) I I ,1I I !<: I i ; ! I I i I ): i I I I ......' (' I ) ,.... I \ I I I ::t~~N;1 BERGSCHRUND 1 II. N .H ! Iii ~ ¡ , Rule 2. The Alpine Oil Pool is defined as the accumulation of oil and gas common to and correlating to the interval found in the Berg 1 well between 6876 and 6976 MD. , Iii ""..... ,,. ¡ 1f! Top Alpine ·v.æ/ i ~ ! i \ i I i II ! i J í I I I Sandstone, quartzose, jl ! ¡ ¡ vf-f grained, well sorted, I I II! ¡I burrowed, glauconitic I I ! :Ii I¡ I I' Ii I i I I I I ! I ! I : I , í I I f j ¡ [ Iii! ! '(I . 1.11 ! I 11: Sandstone and Siltstone, i I I ¡ii quartzose, silt-vf grained, . I I 30% matrix, burrowed I, I i Ilil II i . Ii I 't.f. ! i i i Iii :1 i I 1'1 .11 I I !! II! I i I I I i I I I i , ¡ 6976, Kingak E \ ¡ ! j ¡"t¡ li¡ I I I! Ii! 1111,1~'li!l ) , ¡! '1 Ii. I I, ··"TlTI" ,! i I I I! ¡I¡j Ii,. ¡I ì!¡¡ i I i ¡ II! ¡Ii i ii! EXHIBIT 5 TOP ALPINE DEPTH STRUCTURE o 1 1 o o oJ )J ~~ {} SCALE 1·' = 8000' CJ, = 100· EXHIBIT 6 PHASE 1 DEVELOPMENT PLAN . 1 1 ~ . . J )J ~~ o SCALE 1'· := 8000· Col. := 100' EXHIBIT 1 Annular Injection Cross Section Base WSak C-3 .. 8 roducer Wellbore Schematic (openhole) 16"Conductor @ 100' MO cemented 10 surface OB-6 LN (3.812" 10) @ 1,000' MD 9-5/8" 36 ppf J-5S BTC Surface Casing @ 2400' TVO cemented 10 surface GLM at 3400' TVD with 1" Bottom Latch GL V Packer Fluid mix: 9.2 ppg KCI Brine with 1200' diesel cap 4-1/2" 12.6 ppf L-80 1ST Mod. R2 Brd Tubing GLM at 5200' TVD í" Bottom La tch GL V Tubing tail to include: DB-6 (3.75"10) LN 4-1/2' 10' PJ and WLEG GLM w/1" Bottom Latch GL V set 2 joints above the X nipple TOC 500' above Alpine HES 'X' LN 2 Jls above packer Packer sel at ~65 degrees 6-118" Openhole completion interval 7" 26 ppf L-BO R3 10rd BTC Mod Production Casing @ ~ 7000' TVD (90 deg) Updated 10/08/98 .. 9 Producer Weilbore Schematic (slotted liner) 16" Conductor to 100' cemented to surface OB-6 LN (3.812" 10) @ 1,000' MO 9-5/8" 36 ppf J-55 BTC Surface Casing @ 2400' TVO cemented to surface GLM at 3400' TVD with 1" Bottom Latch GL V 4-1/2" 12.6 ppf L-80 IBT Mod, R2 8rd Tubing GLM at 5200' TVD 1" Bottom Latch GL V HES 'X" LN Set at 60-65 deg GLM wW Bottom Latch GLV set 2 joints above the liner hanger -- -- -- 7" 26 ppf L-80 R3 10rd BTC Mod Production Casing @ -7000' TVD (90 deg) Packer Fluid mix: 9.2 ppg KCI Brine with 1200' diesel cap 4-112" Liner Assembly: <D - 1 joint blank liner below hanger (V- DB landing nipple ® - blank 4-1/2" liner @- 4-112" slotted liner ®- 2 jts 4-1/2" blank liner 0- 4-1/2" slotted liner 0- PO & 1 jt 4-112" blank liner ®- 4-112" guide shoe -0 -®- ø'®: -------------------- ------------------ ---------- 4-112" 12.6 pp! L-80 R2 8rd 1ST Mod. liner Ilnrl~tp.rI 10f(HHQR : "" 10 ellbore Schematic Injector 16" Conductor @ 100' MD cemented to surface D8-6 LN (3.812" I D) with Model "A3" Injection Valve (2.125" ID) at 1000' MD 9-5/8" 36 ppf J-55 BTC Surface Casing @ 24(}(}' TV D cemented to surface 4-1/2" 12.£3 ppf L-80 1ST Mod. R2 8rd Tubing Packer Fluid: 9.2 ppg KCL brine with N2 or gas freeze protection to 1200' Tubing tai! to include D8-6 LN (3.875" ID) 4-1/2" 10' PJ and WlEG TOC 500' above Alpine Packer (3.875" IDj set 60-65 deg above Alpine Sand ~ - - - ~ . - - - Open hole completion interval 7" 26 ppf L-BO R3 10rd BTC Mod Production Casing ~7000' TVD (90 deg) Updated 10/08/98 . . f7acilitil!s allll «'J( llStl7W1Af!*'ti()llJ~ : · New concepts · Environmental aspects · Construction schedule . · Facility and Drill Site designs e . . · GEOLOGY OVERVIEW · 1998 WELLS = 8000 6 1 1 ~ SCALE 1" = 8000 FT C.I. = 50 STRUCTURE '\ TOP ALPINE C LPI Gamma Ray 7100 A ~ CO CD t: ~ 7150 P SIT PEL FACIES Grain Matrix Glauconite Ave. Ave. Thickness Reservoir Size (%) (%) Poros Perm Range Volume (mm) (%) (md) (ft) (%) .11 VF .10 VF 5-8 <5 10 <5 10-20 < 1 19.3 10 25-101 65% 20.4 30 5-26 30% 17.2 15 5% 1-30 III I III I Nechelik #1 -Q- FIORD #2 / ~ / .-0 ~ \ ~ fõ ~ -- - o 1 Mile 97001S05A02 ALPINE NORTH - SOUTH STRATIGRAPHIC CROSS SECTION NORTH SOUTH ALPINE 3 ALPINE 1A ALPINE 1 ALPINE 1 B NEVE 1 NANUK 1 AVE PERM = 32 KH = 827 AVE PERM = 16 KH = 982 AVEPERIIi!=34 KH = 1032 AVE PERIIi! = 11 KH = 728 AVE PERIIi! =4 KH = 404 AVEPERIIi!=1 KH=7 N 5 98030201AOO J4 TROUGH AMPLITUDE FROM FAR STACK D DATA SCALE 1" == 8000 FT C.!. == 20 FT SCALE 1" == 8000 FT C.L == 20 FT . . 1998 WELLS · CDl-22 Transgressive Horizontal · NUIQSUT Western Delineation · CD2-35 Stillstand Horizontal GOALS · TEST HORIZONTAL PRODUCTIVITY · ADD RESERVES ) FIOR \- o 5000 ~ ALPIN T P,Y IS PAC CASE (3 SEISMIC BA A 1 1 EMPTATION . PTATION . ALPIN RMEABI (KH) ISOPACH . TEMPTATION 1 I I 1 NW TRANSGRESSIVE LCU A I\.LPINE D ET 7" CASING KINGAK E KINGAK D VERTICAL EXAGGERATION - 2.5X SE CONTINGENT Cf2-35 Alpine 1 Proiected '" .,,·.i ... ~-~. . .,.: ... ,t· '.'. " · , "L~ ," . i · . ,:.; . i . , 'i > ÞJ~· ? , :V: .. ,..:' :, ! : . : 'i .," :.. :' 'ii'i: i, I i.. .i·· ~vvv .';(1 :i . : 7 , < ;', .? , . : ' , i i . , : : .; : · . : ~ .~< ..... , . ,: , : · . ~: i,' , ··~H"1-~ : , .J'\', NORTHWEST SOUTHEAST STILLSTAND HORIZONTAL I ] J:I..~M:\ -- LeU MILUVEACH A ALPINE D KINGAK F KINGAK E KINGAK D I ~I - SE:~ . ________ I~ - - I - 2000' Section - ~...... GRO Alpine 1 B Pro ected :~ , , :: : . ., ~: I~~: , . I~AlPine 113 Well Test J : 350 BOPD ¿ 2200 SOPD Post Frac ~ . þ.'t¥ : ~: ~ ,j: .\ I , == xæ .. · -i: r- , ~ i, ., .. " i : ,.' , .' : . .' : , = , ¡ ->-'"-'- !:1i ~. '~"T' ... : : : Î#"!,i ; VERTICAL EXAGGERATION = 12X ...~ Alpille Reservoir Sectioll - Topics · Overview · Alpine FFM Model Review · Base Development Plan · Alpine Positive Factors · Alpine Risk Factors · Summary . . Overview · Current Reservoir Plan of Development · Waterflood in the center of the field · Gas re-injection around the edges of the field . · Alpine Development · Phase 1 - Funded first 50 wells down to 600 md-ft cutoff . Phase 2 - Expected base development case includes an additional 42 wells down to a 200 md-ft cutoff · Key Uncertainties · Productivity · Injectivity · InjectionlProduction Balance · Horizontal Injector and Producer Conformance . Alpine FIlii Field Model . Reservoir Description · Depth · Undersaturated · Aquifer · Permeability - Transgressive - Stillstand · Porosity · Initial Oil Saturation · OOIP (Model) · OOIP (CD-l and CD-2 Access) · Areal Extent · Thickness · Rock Type 7000 feet No Gas Cap None Expected . 1 to 100 md 1 to 30 md 19% 79% 977 MMSTB 875 MMSTB 5 miles wide by 10 miles long o tol00 feet Very Fine Sandstone . , Alpine Full Field Model - . Fluid Properties . · Original Pressure 3200 psi · BP Pressure ....2500 psi · Temperature 160 Degrees F · Oil Gravity 40 Degrees API · Solution GOR 950 SCF/STB · H2S None · C02,N2 <1% · C2+ in Solution Gas 31% . · Reservoir Fluid Viscosity .45 cp · Formation Volume Factor 1.5 RVB/STB Alpi"e Full Field M()del . Full Field Model · 28000+ grid cells · 92 x 62 x 5 layer model · 500' by 500' cells (5.7 acres) · 5layers · Grid developed from 2-D seismic data · Reservoir Properties - porosity - water saturation - horizontal perm - vertical perm . . Oil Saturation at Startup NS - Sect. 2 60 sq. mile foot print Berg. #1 Berg 2A Berg. 2 0] 8IJ(} O]êl)(} (J.66tJt] 0.601)(} 0.54f)(} 0.4800 260' lJ.06IJO 5 miles (J9(J(JtJ 8.84(](J 8. 78{J(J (J.7ê{Jt) (/.66t)(/ (J.4ê(J(J {J.3600 o.3(](JO O. í?40(j (j. 1800 0.1 êO(} 0. (J61)() (J.fJ()(](J (J.54{J(J {J,48t.JtJ Alpine IB Alpine 1 Alpine lA 10 miles {J.7ê{JO 0.66{}0 0.6IJ{]{} (J.54(J(] 0.48IJ{) tJ.42(](] 0.36(](] 0.3f)(](] 0.ê4(](] a.181J(] HAW IOOll#1 Alpine #1 HAW Delineation Well 700' Cllrrent Develop"lent PlaIa - 92 tV ell Case . 92 Well Development Case · Combination of Horizontal and Conventional Wells · Drill down to about 200 md-feet · 3000' between horizontal injectors and producers · 550 acre patterns (horizontal wells) · 2640' between vertical injectors and producers · 320 acre patterns (vertical wells) · Waterflood in the center of the field · Gas injection on the edge of the field · Recovery at 2030 => 365 MMSTB · Peak Oil Rates => 70 MSTB/Day . . .J Base Devel()pn',el'lt Pia" . Positives of Alpine Reservoir · OOIP well understood - 3-D seismic - 11 penetrations through the reservoir · Good connectivity - High Net to gross - Oil from all wells of the same type - Consistent RFT data · Good Sweep efficiency - Low permeability variation - Favorable mobility ratio - Low faulting . . Base Developntent Plal'I . Risk Factors · Low Productivity . - Potential damage during drilling and completion - Low average permeability · Low Injectivity - Very fine grained sandstone may plug up with solids in il\Îected water - Low average permeability · Reservoir Pressure Loss - Il\Îectors expected to have problems keeping up with producers . - No aquifer or gas cap reservoir support mechanisms · Sweep efficiency problems - Not much industry experience with horizontal wells under waterflood - Injector and producer profile control may be a challenge S"m,nary . Working to reduce uncertainties in the base plan · Productivity - Horizontal Production Testing · Injectivity - Possible Long Term Injection Test in 1999 - Evaluate Water Injection Start-up Timing Options - Contingency InfiO Drilling Plans and Longer Injectors · InjectorlProducer Balance - Looking at longer injectors and additional injectors · Horizontal Conformance - Looking conformance in analog fields . . Working within the current project scope and design, significant depletion plan optimization exists · Potential to increase reserves with peripheral horizontal drilling and pattern configuration optimization - · Potential to increase reserves with Miscible WAG Injection . Proposed Alpine Completion Ian Winter 97 -98 Driiling rogram 4-1/2· Cameo BP-6í SSSV Nipple (3.812" !O) for Cameo WROP-2 SCSSV 25" ¡ and OB-6 No-Go Lock (2.25" ID) with 1/4" )( 0.049" s/s control line @ 500' MD 9·5/8" 47 ppf L-80 BTC Surfa.ce Casing @ 3050' TVD 4-1/2" 12.6 ppf L-BO BTC Mod. tubing Tubing tail to include HES 'XN" (3.725" 10) 4-1/2" 10' PJ and WLEG Note-Baker-Iock all components Camco KGB-2LS GLM's (3.909" 10) & 1" Ca.mco OK-181m latch GLV's (3 totai) HES "X" (3.813" 10) 1 JI above GLM Baker Model S-3 Packer (3.875" 10) set <65 deg 4-1/2" Liner Assembly: blank 4-1/2" liner from hanger to 3 jts below 7" shoe ® - 4-1/2" slotted liner (length TBD) ® - 2 jts 4-112" blank liner @+1/2" slotted liner (length TBD) ®- 1 jt 4-1/2" blank liner w/PB @- 4-1/2" PES guide shoe Q) - - - - - - - - - 4- 1/2" 11.6 K-55 BTC Moo. . Mon 3/2/98 4/26 , I 4/19 April 4/12 4/5 3/29 3/22 March 3/15 3/8 3/1 2/22 2/15 Febru 2/8 2/1 1/25 1/18 Janua 1/11 1/4 Alpine Development Drilling Plan - - ID Task Name Start Finish ! 12/28 1 Tundra Travel Approved Wed 1f7/98 Fri 5/1/98 - 2 Prepare Roads & Pad Wed 1f7/98 'ed 2/11/98 - .- ,-,-.. 3 CD1·22 Wed 2/11/98 Sun 415/98 - --._,"' 4 MIRU Pool #6 Wed 2/11/98 Thu 2/26198 - --._._---_._~...._----_._---.._-----,--_...- ___n..______."__,. ,.---....-----..--- 5 Drill CD01-22 Fri 2/27/98 Fri 3/20/98 - ._ "__ ..,.,___.__.h" "__. ._,_"__._._.n. ___ ..__.___.~.__. ___ _..._n__.___.n.__.".___." __._·_.h·____.__"__·"._·.. 6 Test CD1-22 Fri 3/20/98 Sun 4/5/98 - ."__.'__ .n..___"__. _._."___ .. .,__._ ..'_'_"_"_ .. _,___ _ __. ___,u'_......_n..___._... ---',,'-,"."-"-""--', 7 Nuiqsut #1 Fri 3120/98 Thu 4/30/98 - . .- - ..-.----.-.- -.--~_.-.-.__.'_._.. .-- _.-._-_."_.- .."-. ..--.--.-----..--..--.-- --..----..---.----,"--- 8 MIRU Pool #6 Fri 3/20/98 Sun 3/29/98 - - ._._. .__ ... __".. _._,_, __. _.. ___ _._"_ '0" '.____ __". . ______ __.__ .n~ _._ ___._ _.. ---...-.---.-.--.---..- 9 Drill Nuiqsut #1 Mon 3/30/98 Wed 4/15/98 - ---_..,-----.._-.-._---_._------"-------- ----- "- -----, 10 Drill Nuiqsut #1 A Wed 4/15/98 Mon 4/20198 - ____n.._·_._ '___n~___"..__"" u__n________ "__.._ 11 Move across Colville AN Tue 4/21/98 Thu 4/30/98 - ._____u __ _"...._"______." __ _'"u_.__ ___._.. _" _.."'._"___ 12 CD2-35 Sat 3/28/98 Thu 4/30/98 - -,---,_.- ._-- -,-_._,.-._---_. .---- 13 MIRU Doyon #141 Sat 3/28198 Tue 3/31/98 - "__-'._n__ .__ ..__.__..._ __ ..__ ._.~..._.___nu 14 Drill CD 02-35 Wed 4/1/98 Mon 4/20/98 - - ___"____·_.·____..___'H_"_.-___-.____,_ .u· ""___"~_~ "...___.... ..__'.""__"__ u.___._ 15 Test, secure and move Tue 4/21/98 Thu 4/30/98 . Mike Erwin Rolled Up Progress Summa¡y Rolled Up Task Rolled Up Milestone 0 Page . Task Progress Milestone Project Project overview clate.MPP Date: Mon 3/2/98 A ALPINE DEVELOPMENT DRILLING . .. . Doug Chester .<ii. ,¿it. WASTE MANAGEMENT 1998 · CD1-22 - Cement rinsate to Parker 245 until - Frozen cuttings toCC2A Mud to IR until int csg set - After int csg set, annular injection · Nuiqsut #1 and 1A - Cement rinsate - CDl-22 or Parker 245 - Frozen cuttings to CC2A or Drill Site 4 - Mud to CDl-22 annulus or IR in KRU · CD2-3S Cement rinsate - CDl-22 or Parker 245 - Frozen cuttings to CC2A or Drill Site 4 - Mud to CDl-22 annulus or IR· KR. . . WASTE MANAGEMENT 1999 . . Depth - Camp waste I Uquid(no solids) - Class II permit? . Mudl Cuttings - BällMill Wasb·and recycle gravel -A.J1l1uluslnjection - Cement rinsate - ]j1xplöratiönCuttings . Ball Mill .... Class II well RIG SPECS . . BATCH DRILLING . ·. ISSUES . . . enSIOnS Flìf·"K'lITll Pllll'IS · 1998 Drilling Results - ~VlT'Au.N<-'} PIZ~w7AT o~1 · Revised Plan of Development · Field Rules Hearing · EOR Certification's"r<'\61iM~ IN 1~~'1 . · Area Injection Order . ARCO Alaska, Inc. Project Timeline for Alaska Oil and Gas Conservation Commission J F M A M J J A SON D J F M A M J J A SON D Submit Tabasco Pilot Waterflood I Injection Application Begin Tabasco Pilot Waterflood (April 15, 1998) . . Submit Tabasco Area Injection Order Application and Request for Pool Rules for concurrent processing by AOGCC Begin Tabasco Development Drilling and Production . I . Submit Tarn Area Injection Order Application and Request for Pool Rules for concurrent processing by AOGCC. Begin Tarn Development Drilling . Begin Tarn Production I . '. Submit Alpine Area Injection Order Application and Request for Pool Rules 1 Begin Alpine Development Drilling .
