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Home My WebLink AboutDIO 018DISPOSAL INJECTION ORDER #18 COLVILLE RIVER FIELD ALPINE OIL POOL 1. November 3, 1998 Notice of Hearing, Affidavit of Publication and Bulk Mailing Address 2. December 3, 1998 Arco’s Application for DIO Colville River Unit North Slope Basin 3. December 3, 1998 Transcript of Hearing 4. May 6, 2007 ConocoPhillips Alaska, inc. request for an Administrative Approval to adjust surveillance Logging and plug depth tags 5. August 3, 2007 Memo to file and supporting documentation (DIO18-001) 6. ------------------ Annual disposal well performance Disposal Injection Order #18 . . ,. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 ....... Re: The APPLICA nON OF ARCO ) ALASKA, Inc. for disposal of Class II ) oil field wastes by underground injection ) in the Colville River Unit well WD-2. ) Disposal Injection Order No. 18 Colville River Unit Colville River Unit Well WD-2 April 19, 1999 IT APPEARING THAT: 1. By letter dated November I, 1998, ARCO Alaska, Inc. ("ARCO") requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to inject Class II waste fluids in the Colville River Unit well WD-2. Meetings were also held at ARCO on November 10, 1998. 2. The Commission published notice öf opportunity for public hearing in the Anchorage Daily News on November 3, 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. Concurrently, the commission heard testimony to establish pool rules for the Colville River Field, Alpine Oil Pool. FINDINGS: 1. A~CO is the operator of the Colville River Unit ("CRU"). There are no other operators within a one-quarter mile radius of the proposed disposal injection project. 2. The state of Alaska is the only surface owner within a one-quarter mile radius of the proposed disposal injection project. 3. The Colville River Unit WD-2 disposal well ("CRU WD-2") will be the initial well drilled from the first of two development pads used to develop the Alpine Oil Pool. 4. Bergschrund # 1 and CD 1-22 are the only wells within one-quarter mile of the CRU WD-2 well. Bergschrund # I does not penetrate the injection or arresting zones but does encounter tl1e top oftl1e confining zone. Well CD 1-22 does not penetrate the confining zone. ARCO does not anticipate drilling any other well within a one-quarter mile radius of the CRU WD-2 penetration of the disposal injection intervals. 5. The proposed disposal injection intervals are the Permo-Triassic Ivishak and the Triassic Sag River Fonnations, which may be defined in the Sohio Nechelik # 1 well between 8432 feet and 9540 feet measured depth. The Sohio Nechclik # I well was cored throughout the Ivishak Formation, and appears to contain a typical and representative section ofthe disposal intervals. Disposal Injection Order No _ Apri119, 1999 . Page 2 6. The fluvial sandstoncs and conglomcratcs ofthc lowcr proposcd injection zonc in the Ivishak Formation havc a gross thickncss of 600 to 700 fcct and a net thickness of approximately 400 fcct (16% or grcatcr porosity) and is cxpcctcd to bc the predominant injection zone in the CRU area. 7. The shallow marine sandstones ofthc uppcr proposcd injcction zonc in the Triassic Sag River Formation have gross thickness of 50 fcct and a nct thickness of 35 feet (porosity greater than or cqual to 19% and avcragc pcrmcability of 120 millidarcies) in the CRU area. 8. The upper confining zone consists of approximatcly 1300 fcct of siltstones and shales with vcry low porosity and pcrmeability within thc Jurassic Kingak Formation. The lower confining zone consists of betwccn 200 fcct and 250 fcct of silty shales within the Permian Kavik Formation. 9. Approximately 350 fcct to 400 fcet of shale, siltstonc, and limcstone of the Triassic Shublik Formation scparate thc Ivishak from thc Sag River Formation in the Colville River Delta arca. 10. ARCO plans to run cemcnt quality logs within thc surfacc casing and long string ofCRU WD-2 well. 11. The CRU WD-2 complction dcsign consists of a 16" conductor sct at 117 fcet measured depth ("MD"), 9 5/8" surface casing set at 2800 fcct MD and ccmcntcd to surface, and a tapered completion string consisting of 7 5/8" to 1200 fcct and 7" to a total depth of 10,322 feet MD (9900 feet TVDss). 12. ARCO intends to test tubing and casing integrity according to 20 AAC 25.412 prior to initiating disposal opcrations. 13. ARCO intends to usc the CRU WD-2 for disposal of oil and gas waste fluids and does not envision using it for disposal of muds and cuttings,.exccpt occasionally. 14. ARCO expects to have a ball mill capablc of grinding and washing gravel on location. They propose to wash gravel and usc it as maintcnance gravel and dispose of muds and cuttings that are not recyclablc through the annuli of wells authorized by the Commission for that purpose under 20 AAC 25.080. 15. ARCO expects to dispose of approximately 4 million barrels of waste associated with well workover, stimulation and production opcrations and 14 million barrels of produced water. 16. Average injection ratc is cxpectcd to initially bc up to 300 barrels pcr day ("BPD"). This rate is expected to increase when source watcrflood breakthrough occurs in the Alpine Oil Pool, about ycar five and continue to climb to a maximum of 10,000 BPD at year fourteen. Before thc ratc reachcs 10,000 BPD, watcr-conditioning equipment will be installed for the purpose of enhanced oil rccovery and the produced water will be redirected into the oil rescrvoir. The avcragc injcction ratc is cxpccted to drop at that time to the 300 - 500 BPD range. Disposal Injection Order No.1t April 19, 1999 . Page 3 17. Maximum operating pressure will vary depending on the condition of the injection zone. Surface pressure is expected to range from 1700 to 3200 psi. 18. ARCO expects the disposal zoncs to progrcssively bccome plugged in the region around the wellbore. ARCO expccts to maintain injcctivity by occasionally stimulating or fracturing past the restriction when performancc indicates the intcrval is pluggcd. 19. ARCO will conduct pcriodic surveillancc of disposal opcrations through the use of temperature surveys, prcssurc transicnt tcsts, stcp ratc tcsts, thcrmal dccay time logs, well bore tracer surveys, disposal rate and prcssure monitoring, mechanical integrity tests, and tagging effective dcpth to dctermine fill buildup. 20. Reservoir surveillancc tcchniques will also bc uscd for tracking ncar wcllborc fluid movement, establishing dimcnsions of disposal fracturc, of disposal storage volume and dctecting changes in disposal zonc charactcristics. 21. Calculated water salinity rangcs from 15,000 to 18,000 milligrams pcr liter ("mg/I") total dissolved solids ("TDS") throughout thc Crctaccous and oldcr stratigraphic section in the Colville Delta area. Watcr samplcs collccted from drill stcm and production testing of several wells in the gencral Colvillc Delta arca yieldcd 18,150 to 24,300 mg/l TDS. 22. The U.S. Environmental Protcction Agcncy ("EPA") issued a Class I disposal permit for the CRU WD-2 well on Fcbruary 3, 1999. CONCLUSIONS: 1. The rcquirements of20 AAC 25.252(c) have bccn met 2. There are no underground sources of drinking watcr ("USDWs") underlying the Colville River Unit. 3. When operating under this ordcr waste fluids authorized for disposal in the Colville River Unit must consist exelusively of Class II waste fluids. 4. Permeable strata that reasonably can be expcctcd to accept thc total volume of disposal fluids anticipated for this projcct are present in thc Ivishak and Sag Rivcr Formations within the Colville Rivcr Unit. 5. Waste fluids will be containcd within appropriatc rcceiving intcrvals by confining lithology, cemcnt isolation ofthc pcrforatcd intcrvals and opcrating paramcters. No disposal will bc authorized bcfore thc Commission cvaluatcs ccmcnt bond logs and cement records to detcrminc thc adequacy ofthc ccment to isolate disposal intervals. 6. Disposal injection opcrations in the CRU WD-2 wcll will be conducted at rates and pressures below those rcquired to fracture the confining zoncs dcfined in this order. 7. Periodic stimulation of the disposal intcrval will be rcquired to placc solids into the formations. Fractures or disaggregation of the cloggcd porcs and rock matrix are Disposal Injection Order NO.. April 19, 1999 . Page 4 intended to provide pathways to transport wastc fluids to undamagcd storage within the disposal zone. Fracture growth can be containcd within thc disposal interval by controlling thc rate and volumc of injection bclow thc Icvel rcquired to fracture the confining intervals. 8. Surveillance of disposal operations and demonstration of mechanical integrity every four years will provide information to ensure waste fluids arc containcd within the disposal interval. 9. Disposal injection operations in the Colvillc Rivcr Unit will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT: Rule 1 Authorized Injcction Strata for Disposal Class II oil field waste may be injectcd into the Colvillc River Unit WD-2 well, in conformance with Alaska Administrative Code Titlc 20, Chapter 25, for disposal into strata that correlates with the 8432 feet to 9540 feet measured depth intcrval in the Sohio Alaska Petroleum Company Nechelik # 1 well. Rule 2 Demonstration of Tubing/Casing Annulus Mcchanical Intcgrity A schedule must be developed and coordinated with thc Commission that ensures the tubing-casing annulus is pressure tested prior to initiating disposal and at least once every four years thereafter. The casing must bc tcstcd at a surfacc pressurc of 1500 psi or 0.25 psi/ft multiplied by the true vertical depth of the packer, whichevcr is greater, but may not be subjected to a hoop stress greater than 70% ofthc minimum yicld strength ofthe casing. The test pressure must show stabilizing pressure and may not decline morc than 10% within thirty minutes. The Commission must be notified at least twenty-four (24) hours in advancc to enable a representative to witness prcssure tcsts. Rule 3 Disposal Fluids Only Class II fluids may be injectcd into the CRU WD-2 wcll while opcrating under the authority of this order. ARCO shall advisc the Commission if it cxpccts to initiatc routine disposal of muds and cuttings in the well. Rule 4 Well Integrity Failure Whenever disposal ratcs, opcrating pressure observations or prcssurc tcsts indicate pressure communication or leakagc of any casing, tubing or packer, thc opcrator must notify the Commission on the first working day following the obscrvation, obtain Commission approval of a plan for corrective action and obtain Commission approval to continue injection. Rule 5 Survcillance A baseline temperature survcy from surface to total dcpth, initial stcp rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are requircd prior to initiation of Disposal Injection Order N. April 19, 1999 . Page 5 regular disposal injection. Rcgular fill dcpth tags and survcillance logging are required at least once annually or as warrantcd following consultation with the Commission. Operating parametcrs including disposal ratc, disposal pressure, annulus prcssurcs and volume of solids pumped must bc monitored and rcportcd according to rcquircmcnts of20 AAC 25.432. An annual performance report will be required including ratc and prcssurc performance, surveillancc logging, fill dcpth, survcy rcsults, and volumctric analysis of the disposal storage interval, estimate of fracture gro\\1h, if any, and updatcs of opcrational plans. Report submission is due on or about July I. Rule 6 Administrativc Action Upon request, the Commission may administratively rcvisc and rcissuc this ordcr upon proper showing that any changes are based on sound enginccring practices and will not allow waste fluids to escape from the disposal zone. DONE at Anchorage, Alaska and datcd April 19, 1999 Robcrt N. Chnstcnson, P.E., Chairman Alaska Oil and Gas Conscrvation Commission ~,~~ Camillé Oechsli, Commissioncr Alaska Oil and Gas Conscrvatio ~ .~ \. AS 31.05.080 provides that within 20 days aner 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. 'nle 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 aner the application for rehearing was filed). . ~v~væ (ill~ ~~~~[K(~ . AI/ASIiA. OIL AND GAS CONSERVATION COMMISSION SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL DIO 18.001 Ms. MJ Loveland Well Integrity Project Supervisor ConocoPhillips Alaska Inc. P.O. Box 100360 Anchorage, AK 99510-0360 RE: Surveillance Frequency - Request for Administrative Approval Dear Ms. Loveland: Pursuant to Rule 6 of Disposal Injection Order ("DIO") 18.000, the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission") hereby grants ConocoPhillips Alaska Inc. ("CP AI")'s request for administrative approval to reduce the frequency of surveillance logging and fill depth tag requirements to not less than once every two years. By letter dated May 6, 2007 CP AI requested the Commission reduce the required frequency of surveillance logging and fill depth tags to a biennial cycle for Colville River Unit well WD-02 (PTD 198-258). DIO 18, Rule 5 currently requires such surveillance "at least once annually or as warranted following consultation with the Commission." Well WD-02 is carries approvals for underground injection from the Commission (UIC Class II) and the Environmental Protection Agency (UIC Class I). The Commission findings based on a review of this request and Commission well files include the following: 1. Well WD-02 has been used primarily for the disposal injection of Class I and Class II wastes generated in conjunction with the Alpine Field development; 2. Sound well integrity and confinement of injected wastes has consistently been demonstrated through daily well performance monitoring, well integrity testing, and surveillance logging; 3. The Environmental Protection Agency modified its UIC Class I permit (No. AK- 11003-A) based on historical mechanical integrity demonstrations, reducing the frequency of surveillance logging and fill depth tag requirements from an annual cycle to a biennia cycle; . . Ms. MJ Loveland August 3, 2007 Page 2 of2 4. The risk of damage to the wellbore and resulting operational problems may be reduced with less frequent well interventions; 5. Consistency among all disposal wells will mlmmlze both confusion and duplication of effort regarding surveillance requirements; and 6. There are no underground sources of drinking water underlying the Colville River Unit. Performance monitoring of injection operations associated with Colville River Unit Well WD-02 provides an accurate and timely assessment of any potential well integrity problems. Reducing the frequency of surveillance logging and fill depth tags will not compromise overall well integrity so as to threaten the environment or human safety. Accordingly, DIO 18, Rule 5 is hereby amended to provide as follows: Rule 5, Surveillance A baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to initiation of regular disposal injection. Regular fill depth tags and surveillance logging are required at least once every two years or as warranted following consultation with the Commission. Operating parameters including disposal rate, disposal pressure, annulus pressures and volume of solids pumped must be monitored and reported according to requirements of20 AAC 25.432. Submittal of an annual performance report will be required on or about July 1 of each year. The report shall include rate and pressure performance, a volumetric analysis of the disposal storage interval, an estimate of fracture growth, if any, and updates of operational plans. If completed, results of logging, fill depth, or other surveillance surveys designed to document disposal injection performance and confinement of injected fluids shall also be included in the annual report. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Daniel T. Seamount, Jr. Commissioner . . Page 1 of 1 Colombie, Jody J (DOA) Colombie, Jody J (DOA) Monday, August 06, 2007 3:31 PM Mciver, C (DOA); 'Alan Birnbaum <""Alan J Birnbaum "> (alan.birnbaum@alaska.gov)'; 'Aleutians East Borough'; 'Anna Ratr; 'Arthur C Saltmarsh'; 'Arthur Copoulos'; 'Barbara F Fullmer'; 'bbritch'; 'Bill Fowler'; 'Bill Walker'; 'Brad McKim'; 'Brandon Gagnon'; 'Brian Gillespie'; 'Brian Havelock'; 'Brit Lively'; 'buonoje'; 'Cammy Taylor'; 'carol smyth'; 'Cary Carrigan'; 'Catherine P Foerster'; 'Charles O'Donnell'; 'Chris Gay'; 'Christian Gou-Leonhardt'; 'Christine Hansen'; 'Cliff Posey'; 'Cody Rice'; 'Dan Bross'; 'dapa'; 'Daryl J. Kleppin'; 'David L Boelens'; 'David Steingreaber'; 'ddonkel'; 'Deanna Gamble'; 'Deborah J. Jones'; 'doug_schultze'; 'Evan Harness'; 'eyancy'; 'Francis S. Sommer'; 'Fred Steece'; 'Garland Robinson'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gregg Nady'; 'gregory micallef; 'gspfotr; 'Hank Alford'; 'Harry Engel'; 'jah'; 'James B Regg'; 'James M. Ruud'; 'James Scherr'; 'Janet D. Platt'; 'jdarlington'; 'jejones'; 'Jerry McCutcheon'; 'Jim White'; 'Jim Winegarner'; 'Joe Nicks'; 'John Garing'; 'John S. Haworth'; 'John Spain'; 'John Tower'; 'John W Katz'; 'Jon Goltz'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kristin Dirks'; 'Laura Silliphant'; 'Lois'; 'Lynnda Kahn'; 'mail=akpratts@acsalaska.net'; 'mail=crockett@aoga.org'; 'mail=foms@mtaonline.net'; 'Mark Dalton'; 'Mark Hanley'; 'Mark Kovac'; 'Mark P. Worcester'; 'Marquerite kremer'; 'marty'; 'Matt Rader'; 'mckay'; 'Meghan Powell'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'Nick W. Glover'; 'Patty Alfaro'; 'Paul Decker'; 'Paul Winslow'; 'Randall Kanady'; 'Randy L. Skillern'; 'rcrotty'; 'rmclean'; 'Robert Campbell'; 'Roger Belman'; 'Rosanne M. Jacobsen'; 'Rudy Brueggeman'; 'Scott Cranswick'; 'Shannon Donnelly'; 'Sharmaine Copeland'; 'Sondra Stewman'; 'Sonja Frankllin'; 'stanekj'; 'Stephen F Davies'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'tablerk'; 'Tamera Sheffield'; 'Temple Davidson'; 'Terrie Hubble'; 'Thomas E Maunder'; 'Tim Lawlor'; 'Todd Durkee'; 'Tricia Waggoner'; 'trmjr1'; 'Walter Featherly'; 'Walter Quay'; 'Wayne Rancier' Subject: Public Notice Redoubt Unit; Admin Approvals Colville River Unit A1018B-004 and DIO 18-001 Attachments: AI018B-004.pdf; DI018-001.pdf; Public Notice Redoubt Unit.pdf From: Sent: To: 8/6/2007 Mary Jones XTO Energy, Inc. Cartography 810 Houston Street, Ste 2000 Ft. Worth, TX 76102-6298 George Vaught, Jr. PO Box 13557 Denver, CO 80201-3557 John Levorsen 200 North 3rd Street, #1202 Boise, 10 83702 Baker Oil Tools 4730 Business Park Blvd., #44 Anchorage, AK 99503 Ivan Gillian 9649 Musket Bell Cr.#5 Anchorage, AK 99507 Jack Hakkila PO Box 190083 Anchorage, AK 99519 Kenai National Wildlife Refuge Refuge Manager PO Box 2139 Soldotna, AK 99669-2139 Cliff Burglin PO Box 70131 Fairbanks, AK 99707 Williams Thomas Arctic Slope Regional Corporation Land Department PO Box 129 Barrow, AK 99723 . . David McCaleb IHS Energy Group GEPS 5333 Westheimer, Ste 100 Houston, TX 77056 Jerry Hodgden Hodgden Oil Company 408 18th Street Golden, CO 80401-2433 Michael Parks Marple's Business Newsletter 117 West Mercer St, Ste 200 Seattle, WA 98119-3960 Schlumberger Drilling and Measurements 2525 Gambell Street #400 Anchorage, AK 99503 Jill Schneider US Geological Survey 4200 University Dr. Anchorage, AK 99508 Darwin Waldsmith PO Box 39309 Ninilchick, AK 99639 Penny Vadla 399 West Riverview Avenue Soldotna, AK 99669-7714 Bernie Karl K&K Recycling Inc. PO Box 58055 Fairbanks, AK 99711 Mona Dickens Tesoro Refining and Marketing Co. Supply & Distribution 300 Concord Plaza Drive San Antonio, TX 78216 Richard Neahring NRG Associates President PO Box 1655 Colorado Springs, CO 80901 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Ciri Land Department PO Box 93330 Anchorage, AK 99503 Gordon Severson 3201 Westmar Cr. Anchorage, AK 99508-4336 James Gibbs PO Box 1597 Soldotna, AK 99669 Richard Wagner PO Box 60868 Fairbanks, AK 99706 North Slope Borough PO Box 69 Barrow, AK 99723 \(~ \ \~f c:V/l \ e. 10/ ( ib\1( 6 2020 Annual Disposal Well Performance Report WD-02 API 50-103-20285-00-00 Undefined Disposal Pool Colville River Unit July 12, 2021 INTRODUCTION This report is prepared in accordance with Rule 9 of Area Injection Order No. 18E, dated March 4, 2021, which requires the submission of an annual performance report for slurry injection wells, and the requirements of 20 AAC 25.432 (Report of Underground Injection). Well WD-02, which was drilled and completed in the Ivishak Formation (undefined disposal pool) as a Class I well in April 1999, continued to serve as the primary source of disposal for camp fluids in 2019. CLASS I DISPOSAL WELL WD-02 Injection Volumes Fluid injection volumes for the 12-month period of January 2020 through December 2020 totaled 362,821 bbls. This represents a monthly average of 30,235 bbls. Cumulative injection into the Sadlerochit Group since the start of the project is 7,182,195 bbls. Injection volumes for WD-02 are summarized in both table and plot form as Attachments 1 and 2. Injection Rates The injection pumps operate on level controls located on upstream holding tanks. Alpine base camp effluent water was the primary fluid injected down WD-02 in 2020, hence injection volumes varied in response to field manpower and staffing. The injection pumps are operated at 15 - 20 gpm each, up to the 3,500 psi allowable injection pressure. The maximum allowable wellhead injection pressure was increased to 3,500 psi with the re-issuance of the EPA permit in March 2019. Injection Pressures Injection pressures are monitored and recorded continuously (Attachment 2). Normal wellhead pressure when the pump is offline ranges from 1,200 - 1,500 psi. With the pumps running at 20 - 60 gpm, injection pressure typically ranges from 1,200 - 1,700 psi. Annulus Pressures Annulus pressures are monitored and recorded continuously (Attachment 2). When produced formation fluids are disposed of into WD-02, the hot fluids expand and elongate the tubing 2020 CRU Disposal Well Performance Report WD-02 1 string, which impacts the annulus volume, increasing the annulus pressure. Plant operators bleed off fluid from the annulus as a precaution to avoid annulus pressures reaching the 1,500 psi operating limit. The annulus pressure averaged 872 psi during 2020. On February 28, 2020, the annual EPA MITIA was performed. The results are as follows: • EPA witnessed by Jason Selitsch and Ryan Gross; MITIA passed at 3,520 psi Depth Tags Mechanical integrity work was aligned with the EPA annual integrity testing on CD1-01A. WD- 02’s fill was tagged on February 28, 2020 at 9,873’ RKB. Fracture Growth The surface fracture pressure of the Ivishak Formation, as measured during the step rate test conducted April 11, 1999, was 1,984 psi. This pressure coincides with an injection rate of 1.38 bpm, or 1,987 bpd. The associated bottomhole fracture pressure extrapolated from the step test data is 6,259 psi. This equates to a gradient of 0.66 psi/ft, or fluid equivalent of 12.7 ppg. With the exception of short-term injection periods, tubing tests, and miscellaneous data spikes, the injection pressures have not exceeded the surface fracture pressure for any extended period of time during 2020. Wellwork Event Summary WD-02 Date: Event: 2/29/2020 EPA WITNESSED (JASON SELITSCH & RYAN GROSS) PERFORMED WATER FLOW STATIONS LOOKING FOR UP FLOW AT 9449', 9434', AND 9409'. NO UP FLOW DETECTED. PERFORM INJECTION PROFILE. FIELD SPLITS: ZONE 9803' - 9818' = 25%, ZONE 9837' - 9867' = 75% 2/28/2020 EPA WITNESSED (JASON SELITSCH & RYAN GROSS) MIT-IA PASSED TO 3520 PSI. 2/28/2020 WEATHER DELAYED START. TAGGED FILL @ 9873' RKB w/ 2.68" G-RING. LOG 24 ARM CALIPER FROM 9838' SLM TO SURFACE. **GOOD DATA** READY FOR E- LINE. IN PROGRESS 2020 CRU Disposal Well Performance Report WD-02 2 ATTACHMENT 1: WD-02 2020 INJECTION SUMMARY TABLE Well:WD-02 Disposal Order:18 Field:API: Pool:Permit to Drill:198-258 Pool Code:120036 Days In Tubing Pressure Tbg Pressure Casing Pressure Csg Pressure Cumulative Operation Max Pressure Avg Pressure Max Pressure Avg Pressure Liquid (bbl)Gas (mcf)Liquid (bbl)Gas (mcf)Liquid (bbl) January 31 1,863 1,708 1,112 963 1,153 0 35,734 0 35,734 February 29 2,865 1,701 1,836 893 1,059 0 30,711 0 66,445 March 31 2,701 1,605 1,715 761 1,291 0 40,019 0 106,464 April 30 1,823 1,614 843 764 1,269 0 38,084 0 144,548 May 31 1,708 1,513 825 769 880 0 27,271 0 171,818 June 30 1,791 1,559 804 763 892 0 26,747 0 198,565 July 31 1,780 1,611 1,017 828 953 0 29,528 0 228,094 August 31 2,955 1,587 1,456 997 863 0 26,745 0 254,839 September 30 1,966 1,551 1,036 969 968 0 29,045 0 283,884 October 31 1,751 1,563 978 941 866 0 26,843 0 310,727 November 30 1,767 1,587 1,005 927 852 0 25,570 0 336,298 December 31 1,781 1,586 974 925 856 0 26,523 0 362,821 2,063 1,599 1,133 875 992 0 30,235 0 Monthly Total Colville River Unit 50103202850000 Undefined Disposal Pool Daily AverageMonth Monthly Average January through December 2020 Injection Summary 2020 CRU Disposal Well Performance Report WD-02 3 ATTACHMENT 2: WD-02 2020 INJECTION SUMMARY PLOT 2020 CRU Disposal Well Performance Report WD-02 4 2020 Annual Disposal Well Performance Report CD1-19A API 50-103-20294-01-00 Undefined Disposal Pool Colville River Unit July 12, 2021 INTRODUCTION This report is prepared in accordance with Rule 9 of Area Injection Order No. 18D, dated March 26, 2009, and the requirements of 20 AAC 25.432 (Report of Underground Injection). Disposal well CD1-19A was drilled and completed in May 2000 to provide a disposal source for Class II fluids generated during wellwork and drilling operations. It was converted to a Class I well in April 2008 and continued to serve as a disposal well for fluids generated during wellwork and drilling operations through May 12, 2012. The CD1-19A well was partially abandoned in May 2013 by placement of cement across the injection zone (Ivishak Formation). CD1-01A was drilled, completed, and placed in service in November 2012. CLASS I DISPOSAL WELL CD1-19A Injection Volumes No fluids were injected into CD1-19A in 2020. Wellwork Event Summary No wellwork. CD1-19A Date Event No wellwork events in 2020 2020 CRU Disposal Well Performance Report CD1-19A 1 2020 Annual Disposal Well Performance Report CD1-01A API 50-103-20299-01-00 Undefined Disposal Pool Colville River Unit July 12, 2021 INTRODUCTION This report is prepared in accordance with Rule 9 of Area Injection Order No. 18E, dated March 4, 2021, and the requirements of 20 AAC 25.432 (Report of Underground Injection). CD1-01A was drilled and completed in September/October of 2012 as a replacement for CD1-19A. CD1- 01A was placed in service in November 2012. CLASS I DISPOSAL WELL CD1-01A Injection Volumes Fluid injection volumes for the 12-month period of January 2020 through December 2020 totaled 292,791 bbls. This represents a monthly average of 24,399 bbls. Cumulative injection into the Ivishak Formation since the start of the project is 2,669,801 bbls. Injection volumes for CD1-01A are summarized in both table and plot form as Attachments 1 and 2. Injection Rates Disposal operations for CD1-01A are recorded via a Micromotion flow rate meter. Various trucks and rig units are utilized to transport and dispose of fluids into this well. Injection rates vary from 0.5 - 4 bpm. Disposed fluids primarily include drilling mud and cuttings, and wellwork fluids. All fluid disposal reports and manifests are recorded and stored at Alpine. The data is displayed graphically in Attachment 2. Injection Pressures Injection pressures are monitored and recorded via MadgeTech pressure gauge transmitters. These reports are summarized in the data plot (Attachment 2). Normal wellhead pressures during disposal operations vary from 2,100 - 3,900 psi. 2020 CRU Disposal Well Performance Report CD1-01A 1 Annulus Pressures Annulus pressures are monitored and recorded, and displayed in graphical form on the well performance plot (Attachment 2). Inner annulus pressure averaged 560 psi during 2020 and remained stable during injection periods. On February 28, 2020, the MITIA for CD1-01A was performed. The results are as follows: • EPA witnessed by Jason Selitsch and Evan Osborne; MITIA passed at 4,220 psi Depth Tags Mechanical integrity work was aligned with the EPA annual integrity testing after CD1-01A was commissioned in November 2012. Fill was tagged on February 29, 2020 at 9,690’ RKB. Multiple other fill tags were made in 2020, please see the Well Work Summary table. Fracture Growth During a step rate test on September 17, 2000, the formation fracture pressure was observed as 6,035 psi using a 9,062’ column of 9.2 ppg brine and 1,700 psi on the wellhead. Using this data, a fracture gradient of 0.665 psi/ft was calculated for the reservoir. During normal operations, injection occurs above this fracture pressure, thus hydraulically fracturing the well. A pressure fall-off (PFO) test was performed on Alpine’s Class II Disposal Well, CD1-19A, on June 19, 2004, after injecting 227,000 bbls of approved fluids for the purpose of estimating fracture growth. The complete test report was submitted on July 26, 2004. Referring to the square root of time plot from the June 2004 PFO, a fracture was observed to close at dt = 7.58 minutes and 6,492 psia, yielding a fracture gradient of 0.716 psi/ft. The elevated fracture gradient can most likely be attributed to poroelastic effects due to the long pumping period. Injection was assumed to enter the formation through the top two perforation sets, thus a fracture height of 35 feet was used in the early-time analysis. A regression fit to the early-time fall-off data resulted in a fracture half-length of 356 feet and a fluid efficiency of 1 percent. A Nolte-Smith plot from the injection data yielded a quarter slope, indicating a Perkins and Kern system, i.e. a wedge-shaped vertically contained fracture, which is growing in length. CD1-01A is of like reservoir quality and is expected to have similar fracture properties as demonstrated by CD1-19A above. 2020 CRU Disposal Well Performance Report CD1-01A 2 Well Work Summary CD1-01A Date: Event: 10/27/2020 TAGGED FILL @ 9692' RKB W/ 10' x 2-1/2" PUMP BAILER, SAMPLE RECOVERED AND TURNED IN TO CWG, MEASURED BHP @ 9692' RKB (5771 PSI / 186* F) JOB COMPLETE 6/29/2020 PUMPED 35 BBLS DSL DOWN TBG FOR FP. 4/11/2020 RIH WITH 2.70" JET BLASTER, PUMP 7 BBLS OILSEEKER FROM 9300', FOLLOWING WITH 65 BBLS PRE FLUSH KCL, 115 BBLS 15% HCL, 195 BBLS 5% MUSOL FROM 9300'-9450'. MAKE A DOWN UP DOWN PASS WHILE JETTING ACID ACROSS PERFS. DISPLACE MUSOL TO END OF COIL WITH DIESEL. TURN OVER TO DSO, JOB COMPLETE. INJECTION TEST WITH SEAWATER .5 BPM WHP 3340/IA 196/OA 559, 20 BBLS 1 BPM WHP 3494/ IA 231/OA 555, 20 BBLS 1.5 BPM WHP 3413/ IA 288/OA 574, 20 BBLS 2 BPM WHP 3507/ IA 320/ OA 596, 20 BBLS 3 BPM WHP 3500/ IA 327/ OA 621, 20 BBLS 4/10/2020 RIH WITH 2.70" JET BLASTER. PUMP A TOTAL OF 215 BBLS 15% HCL ACID ACROSS THE FIRST TWO STAGES FROM 9679'-9768' AND 9483'-9654'. ABLE TO PUMP AT .6 BPM THROUGHOUT THE JOB, FINISH LAST STAGE TOMORROW. JOB IN PROGRESS. 4/9/2020 WAIT ON THIRD PARTY CREWS TO GET STUFF MOVED SO COIL COULD GET SPOTTED IN, MIRU, RIH WIH JET BLASTER. TAG AT 9745' RKB, PU TO 9300'. HAD TROUBLES GETTING FLUID AND SHOWER TRAILER UP AND RUNNING. STACK BACK FOR THE NIGHT, RESTART IN THE AM. 3/5/2020 PERFORM WATER FLOW STATIONS FOR EPA COMPLIANCE. WATER FLOW STATIONS PERFORMED @ 9310', 9295' & 9270' WITH WELL INJECTING 1.5 AND 2.0 BPM. NO UP FLOW DETECTED. WITH WELL INJECTING 1.5 BPM PERFORM IPROF. FIELD SPLITS: 9483' - 9518' = 12%, PERFS BELOW 9679' = 88% 3/3/2020 RIH WITH WATER FLOW TOOLS, GAS TO LOW TO POWER UP MINITRON, POOH AND FILL GAS IN TOOL. 3/1/2020 RIH TO 6000', TURN ON MINITRON FOR RST TOOL. TROUBLESHOOT RST TOOL. POOH. 2/29/2020 TAGGED @ 9690' RKB. LOGGED 24 ARM CALIPER FROM 9690' RKB TO SURFACE. READY FOR E/L. IN PROGRESS 2/28/2020 EPA WITNESSED (JASON SELITSCH & RYAN GROSS) MIT-IA PASSED TO 4240 PSI. Micromotion flow rate and MadgeTech pressure gauge transmitters are installed with an alarm system to detect excess injection pressures and rates. The well is monitored 24 hours a day during injection. The well operates at a maximum 4,200 psig wellhead pressure and an annulus pressure up to 2,000 psig. Continuous, recorded monitoring of volumes of hard piped waste streams are captured through the Alpine automation system. 2020CRU Disposal Well Performance Report CD1-01A 3 ATTACHMENT 1: CD1-01A 2020 INJECTION SUMMARY TABLE 2020 CRU Disposal Well Performance Report CD1-01A 4 ATTACHMENT 2: CD1-01A 2020 INJECTION SUMMARY PLOT 2020 CRU Disposal Well Performance Report CD1-01A 5 ~ +~ ~'+ UNIT~_., STATES ENVIRONMENTALPROTECTIOh..;rENCY 9~~ ~ W REGION iQ 1200 Sixth Avenue Seattle, WA 98101 Reply To ~ ~ APR 2005 Attu Of OCE-082 Mr. Bruce St. Pierre Senior Permit Coordinator Conoco Phillips Alaska., Ina (CPAs Alpine Development Project 700 G Street Anchorage, Alaska 99510-0360 Re: Permit Modification of EPA Class I Injection Well Permit No. AK-11003-A Modification of Class I Well Testing and Reporting Requirements Colville River Unit Class I Well WD-02 Well Dear Mr. St. Pierre: ~',(e~ . (~,~ o.a~ e- This letter is in response to your letter of September 28, 2004, to U.S. Environmental Protection Agency (EPA) requesting a modification of testing requirements for the Colville River Unit (CRU) Class I Well WD-02. Based on information provided in your letter of February 4, 2005, and the history of the well performance of mechanical integrity, modifications to the permit have been incorporated to maintain annual mechanical integrity testing and to perform other tests conditionally based on the results of well performance, metal loss, and other well conditions. 'The EPA will, however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the test results. No written comments were received during the public comment period of March 7, 2005, through April 10, 2005. A public hearing was offered. However, it was canceIled due to the lack of requests for the hearing. Enclosed are the modified EPA Class I UIC program permit for the Class I non- hazardous industrial waste injection well at the CRU, the Fact Sheet, and Public Notice. We appreciate the cooperation of your staff during the processing of the permit modification process. If you have any questions, please call Thor Cutler at (206) 553-1673. ' cere Michael A. Bussell, Director Office of Compliance and Enforcement~~•-;~ Enclosures cc: Pete McGee, ADEC, Fairbanks . John Norman, AOGCC Theodore Rockwell, EPA Anchorage Marcia Cotnbes, EPA Anchorage Prhited on Recycled Paper ~ ~ Page 1 of 18 ISSUANCE DATE AND SIGNATURE PAGE U.S. ENVIRONMENTAL PROTECTION AGENCY UNDERGROUND INJECTION CONTROL PERMIT: CLASS I Permit Number AK-11003-A In compliance with provisions of the Safe Drinking Water Act (SDWA), as amended, (42 U.S.C. 300f-300j-9), and attendant regulations incorporated.bythe U.S. Environmental Protection Agency (EPA) under Title 40 of the Code of Federal Regulations, ARCO Alaska, Inc. (permittee) is authorized to inject non-hazardous industrial waste through up to three Class I injection wells at the Alpine Field of the Colville River Unit of the North Slope of Alaska, into the Ivishak and Sag River Formations, in accordance with conditions set forth herein. Injection of hazardous waste as defined under the Resource Conservation and Recovery Act (RCRA), as amended, (42 USC 6901) or radioactive wastes are not authorized under this permit. Injection shall not commence until the operator has received written authorization from the EPA Director, Region 10 Office of Water, to inject. All references to Title 40 of the Code of Federal Regulations are to all regulations that are in effect on the date that this permit is issued. Appendices are referenced to the Alpine Development Project Underground Injection Control Permit application dated September 1997. This permit shall become effective on February 3, 1999, in accordance with 40 CFR 124.15. This permit and the authorization to inject shall expire at midnight, February 3, 2009, unless terminated. Signed this 3rd day of February, 1999 /s/ Randall F. Smith Randall F. Smith, Director Office of Water U.S. Environmental Protection Agency Region 10 First Modification: effective February 14th, 2000 /s/ Randall F. Smith Randall F. Smith, Director Office of Water U.S. Environmental Protection Agency . Region 10 Second Modification: effective April ~ , ichaei A. Russell, Director Office of Compliance and Enforcemen U.S. Environmental Protection Agency Region 10 • Page 2 of 18 TABLE OF CONTENTS ISSUANCE DATE AND SIGNATURE PAGE .............................................. 1 GENERAL PERMIT CONDITIONS ..................................................... 4 EFFECT OF PERMIT ........................................................... 4 PERMIT ACTIONS ............................................................ 4 SEVERABILITY ................................................................. 4 CONFIDENTIALITY ............................. ............................. 5 GENERAL DUTIES AND REQUIREMENTS .......................................... 5 Duty to Comply ......... ................................................ 5 Penalties for Violations of Permit Conditions .................................... 5 Duty to Reapply............~ ................................ ............... 5 Need to Halt or Reduce Activity Not a Defense ................................... 5 Duty to Mitigate .............................................................. 5 Proper Operation and Maintenance ........................................... 6 Duty to Provide Information ................................................. 6 Inspection and Entry ............... ....................................... 6 Records ................................................................. 6 Reporting Requirements ..................................................... 7 Anticipated Noncompliance ................................................. 8 Twenty-Four Hour Reporting ................................................ 8 Other Noncompliance.......... .......................................... 8 Reporting Corrections .......................................~................ 8 Signatory Requirements ....................................:..............:. 8 PLUGGING AND ABANDONMENT ................................................ 9 Notice of Plugging and Abandonment ......................................... 9 Plugging and Abandonment Report ............................................ 9 Cessation Limitation ........................................................ 9 Cost Estimate for Plugging and Abandonment ..................................... 9 FINANCIAL RESPONSIBILITY .................................. ............... 10 WELL SPECIFIC CONDITIONS ........................................................ 11 CONSTRUCTION ................................. ............................ 11 Casing and Cementing ..........................................._......... 11 Tubing and Packer Specifications ............................................ 11 • • Page 3 of 18 New Welis in the Area of Review ................................ .......... 11 CORRECTIVE ACTION ......................................................... 11 WELL OPERATION ............................................................. 11 Prior to Commencing Injection ............................................... 12 Mechanicallntegrity ........................................................12 Injectionlntervals ................................:........................ 13 Injection Pressure and Rate Limitations ........................... .......... 13 Annulus Pressure ......................................................... 14 Injection Fluid Limitation .................................................... 14 MONITORING ................................................................. 14 Monitoring Requirements ................................................... 14 Continuous Monitoring Devices _ ........ ...................... ........... 14 Alarms and Operational Modifications ......................................... 14 REPORTING REQUIREMENTS ................................................... 14 ,Semiannual Reports .... ............................................... 14 Report Certification ........................................................ 15 REPORTING FORMS ...................................... ....................... 16 ENHANCED SURVEILLANCE PLAN ................................................. 17 i ~~ Page 4 of 18 PARTI GENERAL PERMIT CONDITIONS A. EFFECT OF PERMIT The permittee is allowed to engage in underground injection in accordance with the conditions of this permit. The underground injection activity, otherwise authorized by this permit, shall not allow the movement of fluid containing any contaminant into underground sources of drinking water, if the presence of that contaminant may cause a violation of any primary drinking water regulation under 40 CFR Part 141 or may otherwise adversely affect the health of persons or the environment. Compliance with this permit during its term constitutes compliance for purposes of enforcement with Part C of the Safe Drinking Water Act (SDWA). Such compliance does not constitute a defense to any action brought under Section 1431 of the SDWA, or any other law governing protection of public health ~or the environment from imminent and substantial endangerment to human health or the environment. This permit maybe modified, revoked and reissued, or terminated during its term for cause. Issuance of this permit does not convey property rights or mineral rights of any sort or any exclusive privilege; nor does it authorize any injury to persons or property, any invasion of other private rights, or any infringement of State or local law or regulations. This permit does not authorize any above ground generating, handling, storage, or treatment facilities. This permit is based on the permit application submitted in September 1997. B. PERMIT ACTIONS 1. Modification. Reissuance or Termination This permit may be modified, revoked and reissued, or terminated for cause as specified in 40 CFR 144.39 and 144.40. Also, the permit can undergo minor modifications for cause as specified in 40 CFR 144.41. The filing of a request for a permit modification, .revocation and reissuance, or termination, or the notification of planned changes, or anticipated noncompliance ~on the part of the permittee does not stay the applicability or enforceability of any permit condition. 2. Transfer of Permits This permit is not transferable to any person except after notice to the Director on APPLICATION TO TRANSFER PERMIT (EPA Form 7520-7) and in accordance with 40 CFR 144.38. The Director may require modification or revocation and reissuance of the permit to change the name of the permittee and incorporate such other requirements as maybe necessary under the SDWA. C. SEVERABILITY The provisions of this permit are severable, and if any provision of this permit or the application of any provision of,this permit to any circumstance is held invalid, the application of such provision to other. circumstances, and the remainder of this permit, shall not be affected thereby. • • Page 5 of 18 D. CONFIDENTIALITY In accordance with 40 CFR Part 2, any information submitted to EPA pursuant to this permit may be claimed.as confidential by the submitter. Any such claim must be asserted at the time of submission in the manner prescribed in 40 CFR 2.203 and on the application form or instructions, or, in the case of other submissions, by stamping the words "confidential" or "confidential business information" on each page containing such information. If no claim is made at the time of submission, EPA may make the information available to the public without further notice. If a claim is asserted, the information will be treated in accordance with the procedures in 40 CFR Part 2 (Public Information). Claims of canfidentialityfnr the following information will be denied: 1. The name and address of the permittee. 2. Information which deals with the existence, absence, or level of contaminants in drinking water. E. GENERAL DUTIES AND REQUIREMENTS Duty to Comply The permittee shall comply with all conditions of this permit. Any permit noncompliance . constitutes a violation of the~SDWA and is grounds for enforcement action, permit Termination, revocation and reissuance, modification, or for denial of a permit renewal application; except that the permittee need not comply with, the provisions of this permit to the extent and for the duration such noncompliance is authorized in an emergency permit under 40 CFR 144.34. 2. Penalties for Violations of Permit Conditions Any person who violates a permit condition is subject to a civil penalty not to exceed $27,500 per day of such violation. Any person who willfu{ly or negligently violates permit conditions is subject to a fine of not more than $27,500 per day of violation and/or being imprisoned for not more than three (3) years. 3. Duty to Reapply If the permittee wishes to continue an activity regulated by this permit after the expiration date of this permit, the permittee must apply for and obtain a new permit. To be timely, a complete application for a new permit must be received at least 180 days before this permit expires. 4. Need to Nalt or Reduce Activity Not a Defense It .shall not be a defense for a permittee in an enforcement action that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of this permit. 5. Duty to Mitigate The permittee shall take all reasonable steps to minimize or con•ect any adverse impact on the environment resulting from noncompliance with this permit. • ~ Page 6 of 18 6. Proper Operation and Maintenance The permittee shall, at all times, properly operate and maintain all facilities and systems of treatment and control (and related appurtenances) which are installed or used by the permittee to achieve compliance with the conditions of this permit. Proper operation and maintenance includes effective performance, adequate funding, adequate operator staffing and training, and adequate laboratory and process controls, including appropriate quality assurance procedures. This provision requires the operation of back-up or auxiliary facilities or similar systems only when necessary to achieve compliance with the conditions of this permit. 7. Duty to Provide Information The permittee shall provide to the Director, within a reasonable time, any information which the Director may request to determine whether cause exists for modifying, revoking and reissuing, or terminating this permit, or to determine compliance with this permit. The permittee shall also provide to the Director, upon request, copies of records required to be kept by this permit. 8. Inspection and Entry The permittee shall allow the Director, or an authorized representative, upon the presentation of credentials and other documerits as may be required bylaw to: a. Enter upon the permittee's premises where a regulated facility or activity is located or conducted, or where records are kept under the conditions of this permit; b. Have access to and copy, at reasonable times, any records that are kept under the conditions of this permit; . c. Inspect at reasonable times any facilities, equipment (including monitoring and control equipment), practices, or operations regulated or required under this permit: and d. Sample or monitor at reasonable times, for the purposes of assuring permit compliance or as otherwise authorized by SDWA, any contaminants or parameters at any location. 9. Records a. The permittee shall retain records and all monitoring information, including all calibration and maintenance records and alt original strip chart recordings for continuous monitoring instrumentation, copies of all reports required by this permit and records of alt data used to complete this permit application for a period of at least three years from the date of the sample, measurement, report or application. These periods may be extended by request of the~Director at any time. b. The permittee shall retain records concerning the nature and composition of ail injected fluids until three years after the completion of plugging and abandonment. At the conclusion of the retention period, if the Director so requests, the permittee shall deliver the records to the Director.. The permittee shall continue to retain the records after the three year retention period unless he delivers the records to the Director or obtains written approval from the Director to discard the records. c. Records of monitoring information shall include: (1) The date, exact place, and time of sampling or measurements; • Page 7 of 18 (2) The name(s) of the individual(s) who performed the sampling or measurements; (3) The date(s) analyses, were performed; (4) The name(s) of the individual(s) who performed the analyses; (5) The analytical techniques or methods used; and (6) The results of such analyses. d. Monitoring of the nature of injected fluids shall comply with applicable analytical methods cited and described in Table I of 40 CFR 136.3 or in appendix III of 40 CFR Part 261 or in certain circumstances by other methods that have been approved by the Administrator. e. All environmental measurements required by the permit, including, but not limited to measurements of pressure, temperature, mechanical integrity, and chemical analyses shall be done in accordance with EPA's Quality Assurance Program Plan. f. As part of the COMPLETION REPORT, the operator must submit a PLAN that describes the procedures to be carried out to obtain detailed chemical and physical analysis of representative samples of the waste including the quality assurance procedures used including the following: (1) The parameters for which the waste will be analyzed and the rationale for the selection of these parameters; . (2) The test methods that will be used to test"for these parameters; and (3) The sampling method that will be used to obtain a representative sample of the waste to be analyzed. Where applicable, the Waste Analysis Plan (WAP) from the permit application may be incorporated by reference. g. The permittee shall complete a written manifest for each load of waste received. The manifest shall contain a description of the nature and composition of all injected fluids, date of receipt, source of material received for disposal, name and address of the waste generator, a description of the monitoring performed and the results, a statement stating if the waste is exempt ftom regulation as hazardous waste as defined by 40 CFR 261.4, and any information on extraordinary occurrences. . For waste streams piped more or less continuously from the source(s) to the wellhead, the permittee shall provide for continuous, recorded measurement of the discharge volume and sha(I provide such sampling and testing as may be necessary to provide a description of the nature and composition of all injected fluids, and to support any statements that the waste is exempt from regulation as hazardous waste as defined by 40 CFR 261.4 h. Dates of most recent calibration or maintenance of gauges~and meters used for monitoring required by this permit shall be noted on the gauge or meter. 10. Reportin4 Requirements The permittee shall give notice to the Director, as soon as possible, of any planned physical alterations or additions to the permitted facility or changes in type of injected fluid. • ~ Page 8 of 18 11. Anticipated Noncompliance The permittee shall give advance notice to the Director of any planned changes in the permitted facility or activity which may result in noncompliance with permit requirements. 12, Twenty Four Hour Reporting a. The permittee shall report to the Director any noncompliance which may endanger health or the environment. Any information shall be provided orally within 24 hours from the time the permittee becomes aware of the circumstances. The following shall be included as information which must be reported orally within 24 hours: (1) Any monitoring or other information which indicates that any contaminant may cause an endangerment to an underground source of drinking water. (2) Any noncompliance with a permit condition or malfunction of the injection system. b. A written submission shaA also be provided within five (5) days of the time the permittee becomes aware of the circumstances. The written submission shall contain a description of the noncompliance and its cause, the period of noncompliance, including exact date and times, and, if the noncompliance has not been corrected, the anticipated time it is expected to continue, and steps taken or planried to reduce, eliminate, and prevent recurrence of the noncompliance. 13. Other Noncompliance The permittee shall report all other instances of noncompliance not otherwise reported at the time monitoring reports are submitted. The reports shall contain the information listed in Permit Condition E-12.b. 14. Reporting Corrections When the permittee becomes aware that he failed to submit any relevant facts in the permit application or submitted incorrect information in a permit. application or in any report to the Director, the permittee shall promptly submit such facts or information. 15. Signaton/ Requirements a. All permit applications, reports required by this permit and other information requested by the Director shall be signed by a principal executive officer of at least the level ofvice-president, or by a duly authorized representative of that persona A person is a duly authorized representative only if: (1) The authorization is made in writing by a principal executive of at least the level of vice-president. (2) The authorization specifies either an individual or a position having responsibility for the overall operation of the regulated facility or activity, such as the position of plant manager, operator of a well or a well field, superintendent, or position of equivalent responsibility. A duly authorized representative may thus be either a named individual or any individual occupying a named position. (3) The written authorization is submitted to the Director. • Page 9 of 18 b. If an authorization under paragraph a. of this section is no longer accurate because a different individual or position has responsibility for the overall operation of the facility, a new authorization satisfying the requirements of paragraph a. of this section must be submitted to the Director prior to or together with any reports, information or applications to be signed by an authorized representative. c. Any person signing a document under paragraph a. of this section shall make the following certification: °I certify under the penalty of law that I have personally examined and am familiar with the information submitted in this document and all attachments and that, based on my inquiry of those individuals immediately responsible for obtaining the information, I believe that the information is true, accurate, and complete. 1 am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment." F. PLUGGING AND ABANDONMENT Notice of Pluagina and Abandonment The permittee shall notify the Director no later than 45 days before conversion or abandonment of the well. 2. Plugqinq and Abandonment Resort The permittee shall plug and abandon the well as provided in the PLUGGING AND ABANDONMENT PLAN (Appendix F), which is hereby incorporated as a part of this permit. Within 60 days after plugging any well the permiftee shall submit a report to the Director in accordance with 40 CFR 144.59 (p). EPA reserves the right to change the manner in which the well will be plugged if the well is not proven to be consistent with EPA requirements for construction and mechanical integrity. The Director may ask the permittee to update the estimated plugging cost periodically. 3. Cessation Limitation After a cessation of operations of two years, the permittee shall plug and abandon the well in accordance with the plan unless he: a. Provides notice to the Director; b. Demonstrates that the well will be used in the future; or c. Describes actions or procedures, satisfactory to the Director, that the permittee will take tb ensure that the well will not endanger underground sources of drinking water during the period of temporary abandonment. These actions and procedures shall include compliance with the technical requirements applicable to active injection wells unless waived by the Director. 4. Cost Estimate for Plugqinq and Abandonment a. The permittee estimates the 1997 cost of plugging and abandonment of the permitted wells to be $1,000,000 each b. The permittee must submit financial assurance and a revised estimate in April of each year. The estimate shall be made in accord with 40 CFR 144.62. • .Page 10 of 18 c. The permittee must keep at the facility during the operating life of~the facility the latest plugging and abandonment cost estimate. d. When the cost estimate changes, the documentation submitted under 40 CFR 144.63(f) shall be amended as weft to ensure that appropriate financial assurance for plugging and abandonment is maintained continuously. e. The permittee must notify the Director by registered mail of the commencement of a voluntary or involuntary proceeding under Title 11 (Bankruptcy), U.S. Code, naming the owner or operator as debtor, within 10 business days after the commencement of the proceeding. G. FINANCIAL RESPONSIBILITY The permittee shall maintain continuous compliance with the requirement to maintain financial responsibility and resources to close, plug, and abandon the underground injection well. If the financial test and corporate guarantee provided under 40 CFR 144.63(f) should change, the permittee shall immediately notify the Director. The permittee shall not substitute an alternative demonstration of financial responsibility for that which the Director has approved, unless it has previously submitted evidence of that altemative demonstration to the Director and the Director notes him that the alternative demonstration of financial responsibility is acceptable. • • Page 11 of 18 PART 11 WELL SPECIFIC CONDITIONS A. CONSTRUCTION Casino Cementing and Logging The permittee shall case and cement the well{s) to prevent the movement of fluids into strata other than the authorized injection interval (see II.C.3, below). Casing and cement shall be installed in•accordance with application Appendix F. The permittee shall, at a minimum, run the open- and cased-hole logs as described in application Appendix F. The permittee shall provide not less than ten days advance notice to the Director of a!I cementing operations. 2. Tubing and Packer Specifications The well shall inject fluids through tubing with a packer. Tubing and packer shall be installed in accordance with Appendix F of the permit application. Except as may otherwise be authorized. herein, the packer shall be located not more than 150 feet uphole from the top of the authorized injection zone. With respect to WD-2 completed in April 1999 with the packer as installed at approximately 7865 feet TVD, operation with the packer located at this depth is authorized provided enhanced surveillance continues to demonstrate integrity of the pipe below the packer. See Part ILC.3.(b)(3) . 3. New Wells in the Area of Review New wells within the area of review shall be constructed in accordance with the Alaska Oil and Gas Conservation Commission Regulations Title 20 -Chapter 25. Further, no offsetting wells within the Area of Review (1/4 mile radius) maybe drilled into or below the arresting zone (lower Kingak Formation) as depicted in Exhibit C-2 of the application) unless directed by EPA.. B. CORRECTIVE ACTION The applicant has identified no wells in the Area of Review (AOR) which require corrective action in order to prevent fluids.resulting from injection from moving above the confining zone. If the applicant later discovers that a.well or wells within the AOR require(s) Corrective action to prevent this fluid movement, as described in 40 CFR 144.55, then the applicant shall inform the EPA upon such discovery and provide a corrective action plan for EPA review and approval. If the EPA or the applicant discovers that fluids resulting from injection have moved above the confining zone along the wellbore of a well within the Area of Review, then injection shall cease until the fluid movement problem can be diagnosed ahd corrected. C. WELL OPERATION Prior to Commencing Injection Injection operations pursuant to this permit may not commence until: a. Construction is complete and the permittee has submitted two copies of COMPLETION FORM FOR INJECTION WELLS (EPA Form 7520-9), see APPENDIX; and • Page 12 of 18 (1) The Director has inspected or otherwise reviewed the new injection well and finds if is in compliance with the conditions of the permit; or (2) The permittee has not received notice from the Director of intent to inspect or otherwise review the new injection well within thirteen (13) days of receiving the COMPLETION REPORT in which case prior inspection or review is waived and the permittee may commence injection. b. The operator demonstrates that the well has mechanical integrity as described herein and in Part II.C.3 below and the permittee has received notice from the Director that such a demonstration is satisfactory. The permittee shall notify EPA two weeks prior to conducting this initial Pest so that an EPA representative maybe present. In order to demonstrate there is no significant leak in the casing, tubing or packer, the tubing/casing annulus must be pressure tested to at least 3,500 pounds per square inch gauge (psig) for not less than thirty minutes. Pressure shall show a stabilzing tendency. That is, the pressure may not decline more than 10 percent during the test period and shall experience less than one-third of its total loss in the last half of the test period. If the total loss exceeds 5% or if the loss during the second 15 minute period is equal to or greater than one half fhe loss during the first 15 minutes, the permitee may extend the test period for an additional 30 minutes to demonstrate stabilization.. c. The operator has conducted astep-rate test and submitted a preliminary report to EPA which summarizes the results. 2. During Infection The injection facility shall be manned 24 hours per day by trained and qualified operators during injection. 3. Mechanicallntearity a. Standards The injection well(s) must have and maintain mechanical integrity pursuant to 40 CFR 146.8. b. Prohibition Without Demonstration of Mechanical Integrity Injection operations are prohibited after the effective date of this permit unless the permittee has conducted the following tests and submitted the results to the Director: (1) To detect leaks in the casing, tubing, or packer, the casing-tubing annulus must be pressure tested to at least 3,500 psig for thirty minutes. Pressure shall show a stabilzing tendency as described in II.C.1.b, above. This pressure test is required at a time interval of no more than 12 months between tests. (2) to detect movement of fluids behind the casing, approved fluid movement tests shall be conducted not less often than biennially. Approvable fluid movement tests include, but are not limited to tracer surveys, temperature, noise or other logs. The specific suite of fluid movement tests proposed to satisfy this requirement are subject to prior approval by the Director. Tracer surveys shall be run at injection pressures at least equal to the maximum continuous injection pressure observed in the well in the previous 6 months and the tracer concentration shall be sufficient to Page 13 of 18 ensure detection behind the casing..Copies of all logs shall be accompanied by a descriptive and interpretative report. The initial operational fluid movement tests shall be completed not less than three nor more than nine months after initiation of operation. In the event these initial tests are held after less than six months of operation, tracer surveys shall be run at injection pressures at least equal to the maximum continuous injection pressure observed in the well since the beginning of operation. (3) Continued operation of Alpine WD-02 as originally constructed is dependent uponimplementation by the permittee of the Enhanced Surveillance Plan (ESP) attached to this permit as Appendix B and incorporated herein by reference. In the event the EPA approves relocation of the packer and the permittee completes the packer relocation, the permittee may cease implementation of the ESP. c. Terms and Reporting (1 } Two (2) copies of the fog(s) and two (2) copies of a descriptive and interpretive report of the mechanical integrity tests identified in 3.b shalt be submitted within 45 days of completion of the logging. (2) Mechanical integrity shall also be demonstrated 6y the pressure test in 3.b.(1) any time the tubing is removed from the well or if a loss of mechanical integrity becomes evident during operation. The permittee shall report the results of such tests within 45 days of completion of the tests. (3) After the initial mechanical integrity demonstration, the permittee shall notify the Director of intent to demonstrate mechanical integrity at least 30 days prior to subsequent demonstrations. Such notice must include an indication of the suite of fluid movement tests the permittee proposes to use. In the event that any of the proposed tests has not been previously approved by the Director, this notice shall include: (a) a complete description of such proposed tests, (b) available evidence supporting the applicability of the proposed test, and (c} a description of such back- up procedures as the permittee deems necessary to adequately demonstrate mechanical integrity in the event that the proposed tests fail to do so. (4) The Director will notify the permittee of the acceptability of the mechanical integrity demonstration within 13 days of receipt of the results of the mechanical integrity tests. Injection operations may continue during this 13 day review period. If the Director does not respond within 13 days, injection may continue. (5} In the event that the well fails to demonstrate mechanical integrity during a test or a loss of mechanical integrity occurs during operation, the permittee shall halt operation immediately and shall not resume operation until the Director gives approval to resume injection. (6) The Director may, by written.notice, require the permittee to demonstrate mechanical integrity at any time. 4. Iniection Intervals Injection shall be limited to the Ivishak and Sag River Formations, as depicted in Exhibits C-1 and C-2 of the application. •5. Iniection Pressure and Rate Limitations • ~ Page 14 of 18 The maximum injection pressure, measured at the wellhead, shall not exceed 3200 pounds per square inch (psig). Further, injection pressures and rates shall be limited as needed to prevent the initiation of new fractures or propagation of existing fractures in the upper confining zone (above the J3 marker which separates the upper and lower Kingak Formations) depicted in Exhibit C-2 of the permit application. The permittee shall continuously monitor both the injection rate and pressure. 7. Annulus Pressure The annulus between the tubing and the long string casing shall be filled with a corrosion inhibited non-freezing solution. A positive surface pressure up to 1500 psig is authorized. 8. Infection Fluid Limitation No substance other than those non-hazardous wastes noted in the permit application shall be injected. Neither hazardous waste as defined in 40 CFR 261 nor radioactive waste other than naturally occurring radioactive material (NORM) from pipe scale and sludge shall be injected for disposal D. MONITORING Monitoring Requirements Samples and measurements collected for the purpose of monitoring shaft be representative of the monitored activity. 2. Continuous Monitoring Devices Continuous monitoring devices shall be installed, maintained, and used to monitor injection pressure and rate, and to monitor the pressure of the non-freezing fluid in the annulus between the tubing and the long string casing. Calculated flow rates and calculated volumes are not acceptable. 3. Alarms and Operational Modifications a. The permittee shall install, continuously operate, and maintain alarms to detect excess injection pressures and rates and sign~canf changes in annular fluid pressure. These alarms must be of sufficient placement and urgency to alert operators in all operating spaces. b. The permittee shall instal! and maintain ari emergency shutdown system to respond to losses of internal mechanical integrity as evidenced by deviations in the annular fluid pressure. c. Plans and specifications for the alarms and pressure relief~valve shall be submitted to the Director prior to the initiation of injection. E. REPORTING REQUIREMENTS Semiannual Reports The permittee shall submit serrmiannuai reports to the Director containing the following information: a. Monthly average, maximum and minimum values for injection pressure, rate, and volume Page 15 of 18 shall be reported on INJECTION WELL MONITORING REPORT (EPA Form 7520-8). b. Graphical plots of continuous injection pressure and rate monitoring. c. Raw monitoring data in an electronic format. ' d. Physical, chemical, and other relevant characteristics.of the injected fluid. e. Any well work over or other significant maintenance of downhole or injection-related surface components. f. Results of all mechanical integrity tests performed since the previous report including any maintenance-related tests and any "practice" tests. g. Any other tests required by the Director. 2. Report Certification . All reporting and notification required by this permit shall be signed and certified in accordance with Part I.E.15., and submitted to the following address: Manager, Ground Water Protection Unit U.S. Environmental Protection Agency (OCE-082) 1200 Sixth Avenue Seattle, Washington 98101 • ~ Page 16 of 18 APPENDIX A REPORTING FORMS Enclosed are EPA Forms: 7520-7 APPLICATION TO TRANSFER PERMIT 7520-8 INJECTION WELL MONITORING REPORT 7520-9 COMPLETION FORM FOR INJECTION WELLS • Page 17 of 18 APPENDIX B Enhanced Surveillance Plan 1. This Enhanced Surveillance Plan (Plan) is required pursuant to Part II.C.3.b.3 of the Permit Number AK-1I003-A.. This Enhanced Surveillance Plan was developed to address EPA's concerns about continued casing integrity with respect to the current packer placement in this well. 2. All demonstrations of mechanical integrity described in Permit AK-1I003-A, Part II.C.3.b remain in full force and effect. To summarize, this includes the following; • Standard casing-annulus pressure tests (SAPT) to detect loss of mechanical integrity above the packer. • Fluid movement tests to detect fluid movements behind the casing and loss of mechanical integrity below the packer. Approved tests include, but are not limited to tracer surveys, temperature surveys, noise or other logs as approved by the EPA. 3. To non-destructively evaluate casing condition below the packer, caliper surveys shall be conducted not less often than biennially over all exposed 7" casing between the tubing tail and the inj ection interval. 4. To confirm the results of the annual caliper and tracer surveys, pressure testing of all exposed 7" casing between the packer and the top of the permitted injection interval will be performed conditionally based on the results of the biennial caliper, temperature and oxygen activation (OA) water flow logs instead of every four years. This pressure test will be performed if (a) the~caliper log shows exposed casing wall losses exceed 50% of the casing wall thickness between the bottom of the packer and the top of the permitted injection interval, or (b) the temperature and/or the WFA/OA logs show fluid movement outside the permitted in jection interval. Isolation plugs will be set in the 7" casing within 100 feet of the permitted injection interval and tested through the tubing to a surface pressure of 3500 psig for 30 minutes. Testing specifications will duplicate those specified in Permit 1I003-A Part II.C.I.b. 5. In the event that (1) surveillance determines casing wall losses exceed 50% of the casing wall thickness in any~area of exposed casing between the bottom of the packer tailpipe and the approved injection interval or (2)~ for other reasons, EPA or pernuttee believe the casing integrity may be compromised, surveillance logs and other information shall be reviewed by EPA and permittee to determine if additional surveillance or remedial activities are necessary. 6. Modification to this Enhanced Surveillance Plan must be approved by EPA. • • Page 18 of 18 7. This Enhanced Surveillance Plan; remains in effect until such time as the Plan is modified, or the pernut condition requiring said Plan is eliminated. 8. The EPA will, however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the results of testing. • FACT SHEET Proposed Modifications of Underground Injection Control (LTTC) Permit AK-1I003-A for the Construction anal Operation ofClass INon-Hazardous Industrial Waste Iniection Wells at the Aline/Colville River Unit on the North Slope of Alaska. U.S. Environmental Protection Agency, Region 10 Ground Water Protection Unit, OCE-082 1200 Sixth Avenue Seattle, Washington 98101 March 4, 2005 Introduction ConocoPhillips Alaska, Inc. (CPAI) has requested a modification of the EPA issued Underground Injection Control (UIC) permit for the construction and operation of a Class I non- hazardous industrial waste injection well at the Alpine/Colville River Unit (CRU). The EPA UIC permit for a Class I well was issued on February 3,1999 and is effective through February 3, 2009. To date, one (1) Class Iwell - WD-02 has been drilled and completed and was first placed on injection on May 15, 1999. Overview of Alpine/CRU and Class IWell - WD-02 The CRU field, operated by CPAI is located approximately 250 miles north of the Arctic Circle and 40 rni.les west of the Kuparuk base camp on Alaska's North Slope and is astand-alone, self- contained, completely independent operation. The Alpine field does not have ayear--round road connecting to the existing North Slope infrastructure. Ice roads are therefore built in the winter to bring in supplies. During the 8-9 months per year when ice roads cannot be utilized, Alpine depends uniquely on air support for all supplies. Alpine started oil production in November 2000, with~gas injection start-up in December 2000 and seawater injection start-up in January 2001. Currently the field is producing approximately 120 - 130,000 barrels of oil per day (BOPD). The waste disposal system~is. designed to provide an integrated approach to managing wastes generated from oil production, maintenance operations, the camp sewage system, and some minor liquids from the drilling rig. As stated earlier, a single Class I well, WD-02, is used for disposal for non-hazardous waste fluids generated at the Colville River Field. Well WD-02 was drilled and completed to the Ivishak and Sag River Formations. The perforated injection intervals are from 9459'-10;047' measured depth (MD) (9085'-9651' sub sea) selectively opposite the 7" casing. The well has primarily been used to dispose of these fluids (incl~iding camp grey water) to reduce the need to transport waste from this isolated field to off-site disposal. The well has consistently demonstrated sound mechanical integrity (both internal and external) on an annual basis in compliance with EPA permit requirements since injection was initiated in May 1999. Representatives from EPA were on-site to witness each annual inspection and testing. -1- • ~ EPA has previously determined that there are no underground sources of drinking water (USDWs) beneath the permafrost of the CRU area. The base of the permafrost at the WD-02 site is at 900 feet below ground. Summary of Proposed Action and Permit Conditions CPAI has requested modifications to the frequency of testing and/or the types of testing, and the monitoring requirements as required under the current permit. The proposed permit modifications include the following: (1) Retain the current requirement to demonstrate that the well has internal mechanical integrity based on a standard annulus pressure test (SAPPED) on an annual basis, (2) Modify the time interval from "not less often than atinuall~' to "not less often than biannually" between approved fluid movement tests (both the temperature and the. Water Flow/Oxygen Activation logs are commonly used to confirm. external mechanical integrity) that are used to verify external mechanical integrity and to confirm there is no flow behind the pipe, (3) Modify the current requirement of submitting monitoring reports from a quarterly basis to a seiniannu'al basis, (4) Modify the time interval between caliper surveys over the exposed 7" casing from "not less often than annually" to "not less often than biannually", anal (5) Modify the pressure testing of all exposed 7" casing between the packer and the top of the permitted injection interval to be performed conditionally based on the results of the biannual caliper, temperature and oxygen activation (OA) water flow logs instead of every four years. This pressure test will be performed if (a) the caliper log shows exposed casing wall losses exceed 50% of the casing wall thickness between the bottom of the packer and the top of the permitted injection interval, or (b) the temperature and/or the WFL/OA logs show fluid movement outside the permitted injection interval. As Alpine/Colville River Field is a roadless operation, WD-02 is the primary disposal option for non-hazardous waste fluids. Therefore, by reducing the number of well bore entries, the well work risks will be reduced and the potential for losing the tools down hole with resultant down- time will be greatly reduced. The permit modifications requested by CPAI will not lessen the environmental protection or lower the operating or testing standards. EPA will however, retain its discretion and fle~biIity to either increase or decrease the frequency of testing based on the results of testing. Public Comment The EPA is now requesting public review of the proposed permit modifications. Persons wishing to comment on the~royosed. permit modification may do~so in writing by April 10, 2005. Comments should be accompanied with a basis for the comments and substantiative facts. Please also include the name address and telephone number of the person malans comment.- All written comments and requests should be submitted to EPA to the attention of: Thor Cutler, Ground Water Protection Unit, EPA~(1VIS: OCE-082) 1200 Sixth Avenue, Seattle, WA. 98101 or via electronic mail to cutler.thor(a,epa.~ov. After April 10, 2005, the EPA may choose to finalize the modification as drafted if no substantive comments are received during the public comment period. For further information, please contact Thor Cutler at (206) 553-1673 or via a-mail: cutler.thor(c~epa. Gov -2- • United States Environmental Protection Agency, Region 10 Ground Water Protection Unit, OCE-082 1200 Sixth Avenue • Seattle, Washington 98101 NOTICE OF PROPOSED MODIFICATION OF A CLASS I UNDERGROUND IN3ECTION CONTROL (UIC) PERMIT FOR THE DISPOSAL OF NON-HAZARDOUS INDUSTRIAL WASTE FLUID AT THE COLVILLE RIVER UNIT ON THE NORTH SLOPE OF ALASKA Public Notice Issuance Date: March 7, 2005 Closure Date: Apri110, 2005 Auulicant ConocoPhillips Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 EPA Permit Number: AK1I003-A EPA Region 10 has direct implementation responsibility in Alaska for. the regulation of Class I injection wells through the Underground Injection Control (LTIC) program, which is authorized by Part C of the Safe Drinking Water Act. Class I injection wells are used for the deep disposal of industrial waste into naturally saline ground water, beneath any aquifers which could serve as underground sources of drinking water (USDWs). EPA is proposing to modify a permit issued on February 3, 1999, to ConocoPhillips Alaska, Inc. (CPAI -formerly Arco Alaska, Inc) for up to three (3) Class Inon-hazardous waste injection wells at the Colville River Unit (CRU). To date, one (1) Class I well, WD-02 has been drilled and completed. and was first placed on injection on May 15, 1999. The CRU field, operated by CPAI is located approximately 250 miles north of the Arctic Circle and .40 miles west of the Kuparuk base camp on Alaska's North Slope and is astand-alone, self-contained, completely independent operation. The waste disposal system is designed to provide an integrated approach to managing wastes generated from oil production, maintenance operations, the camp sewage system, and some minor liquids from the drilling rig. A single Class I well, WD-02, is used for disposal ofnon-hazardous waste fluids generated at the Colville River Field. Well WD-02 was drilled and completed to the Ivishak and Sag River Formations. The well has primarily been used to dispose of these fluids (primarily camp grey water) to reduce the need to transport waste from this isolated field to off-site disposal. The well has consistently demonstrated sound mechanical integrity (both internal and external) on an annual basis in compliance with EPA permit requirements since inj ection was initiated in May 1999. Representatives from EPA were on-site to witness each annual inspection and testing. -1- EPA has previously determined that there are no USDWs beneath the permafrost of the CRU area (base of the permafrost is at 900 feet below the surface). CPAI has requested modifications to the frequency of testing and/or the types of testing, and the monitoring requirements as required under the current permit requirements. The proposed modifications will: (1) Retain :the current requirement to demonstrate that the well has internal mechanical integrity using a standard annulus pressure test (SAPT) on an annual basis, (2) Modify the time interval between approved fluid movement tests (to demonstrate external mechanical integrity and no flow behind pipe) from "not less than annually" to "not less often than biennially". (3) Modify the current requirement to submit quarterly monitoring reports to submit semiannually monitoring reports, (4) Modify the time interval between caliper surveys over the exposed 7" casing from "not less often than annually" to "not less often than biennially", and (5) Modify the pressure testing of all exposed 7" casing between the packer and the top of the permitted injection zone interval to be performed conditionally based on the results of the biennial caliper, temperature and water flow log (WFL) oxygen activation (OA} logs instead of every four years. This pressure test will be performed if (a) the caliper log shows exposed casing wall losses exceed 50% of the casing wall thickness between the bottom of the packer and the top of the permitted injection interval, or (b) the temperature and/or the WFL/OA logs show fluid movement outside the permitted injection interval. As Alpine/Colville River Field is a roadless operation, WD-02 is the primary disposal option for non-hazardous waste fluids. Therefore, by reducing the number of well bore entries, the well work risks will be reduced and the potential for losing the tools down hole (and resultant down-time) will be reduced. The permit modifications requested by CPAI will not lessen the environmental protection. or lower the operating or testing standards. EPA will however, retain its discretion and flexibility to either increase or decrease the frequency of testing based on the results of testing. A Fact Sheet which describes the proposed modification and the proposed modified EPA permit are available upon request and can be viewed at www.epa.gov/regionl0/uic.htm 2. Tentative Determinations The Region 10 Office of the EPA has tentatively determined to modify the UIC permit issued to the above listed applicant. 3. Public Comments Persons wishing to comment on the proposed permit may do so in writing by the close of the Public Comment period, April 10, 2005, at 5:00 PM Pacific Daylight Time. All comments should include the name, address, and telephone number of the person commenting, a statement of the basis of any comment, and the facts upon which it is based. All written comments and requests should be submitted to EPA at the above -2- • address to the attention of Thor Cutler, EPA Region 10, Ground Water Protection Unit (OCE-082) 1200 Sixth Avenue, Seattle, WA 98101. 4. Public Hearinus The Environmental Protection Agency has tentatively scheduled a public hearing to be held on Tuesday, April 5, 2005 at 7 p.m. in the Meeting Room of the Hampton Inn, located at 4301 Credit Union Drive (at C Street and Tudor Street) in Anchorage, Alaska. However, this hearing may be canceled in the absence of any'specific written requests for such a hearing. Written requests for a hearing on the proposed permit must be received by Thor Cutler at EPA Region 10, Ground Water Protection Unit (OCE-082)1200 Sixth Avenue, Seattle, WA 98101 or via a-mail at cutler.thor@epa.gov not later than March 30, 2005 at 5 P.M. PDT. 5. Administrative Record The proposed UIC permit and other related documents are on file and maybe inspected at the above address any time between 8:30 a.m. and 4:00 p.m., Monday through Friday. Copies and other information may be requested by writing to the EPA at the above address to the attention of the Manager, Ground Water Protection Unit (OCE-082) or by calling (206) 553-6697. The draft permit and fact sheet are also available from the EPA Alaska Operations •Office, Room 537, Federal Building, 222 West 7th Avenue, # 19, Anchorage, Alaska 99513 and EPA Alaska Operations Office, 410• Willoughby Drive, Suite 100, Juneau, Alaska 99801. Moreover, copies of the draft permit and fact sheet may be viewed at www.epa.gov/regionl0/uic.htm. For those with impaired hearing or speech, please contact EPA's telecommunications device for the deaf (TDD) at (206) 553-1698. For further information, please contact Thor Cutler at (206) 553-1673 (cutler.thor@epa.gov). -3- 1,,, DEPT. OF ENVIRONMENTAL CONSERVATION DIVISION OF WATER WASTEWATER DISCHARGE PERMITS PROGRAM Bruce St. Pierre, ATO 1708 ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 March 9, 2004 Re: Wastewater Disposal Permit No. 48053 Renewal of Permit No. 9821-DB003 Deaz Mr. St. Pierre, • L U . U ~ G (Et v S -~-- Frank Murkowski, Governor 43335 Katifornsky Beach Road Suite No. 11 Soldotna, Alaska 99669 PHONE: (907) 262-5210 FAX: (907} 262-2294 Certified Mai1 7002 2410 0003 5676 9198 Return Receipt Requested The Department of Environmental Conservation has completed its review of your request for the renewal of the above referenced wastewater disposal permit and is issuing ADEC Wastewater Disposal Permit 48053. This permit replaces Permit 9821-DB003 and becomes effective on March 9, 2004. This permit expires at midnight, Februar~3, 2009. This State of Alaska Wastewater Discharge Permit is being issued in accordance with AS 46 and 18 AAC 15. Department regulations provide that if you disagree with this decision you may request an adjudicatory hearing in accordance with 18 AAC 15.200-910. The request should be mailed to the Commissioner, Alaska Department of Environmental Conservation, 410 Willoughby Avenue, Suite#105, Juneau, Alaska 99801-1795, by certified mail, return receipt requested. A copy of the request shall also be sent to the undersigned. Failure to submit a request within thirty days of service of this letter shall constitute a waiver of your right to administrative review of the decision. In addition, any other person who disagrees with this decision may request an adjudicatory hearing within thirty days of service of the enclosed permit. Any hearing granted will be limited to issues related to the issuance of this permit. If an adjudicatory hearing is thereafter granted, all permit conditions remain in full force and effect. Sincere , Oran Woolley Wastewater Disposal Permits - _. _ , ~. • 5TATE OF ALAS; , DEPARTMENT OF ENVIRONMENTAL CONSERVATION DIVISION OF WATER WASTEWATER DISCHARGE PERMITS PROGRAM WASTEWATER DISPOSAL PERMIT Permit 48053 Date: March 9, 2004 This wastewater discharge permit is issued to ConocoPhillips Alaska, Inc. for the disposal of wastewater resulting from oil and gas production and associated support facilities. The waste will be disposed of by subsurface injection into the Ivishak and Sag River Formations through any of three (3) Class I injection wells, identified as the Alpine Field main facility pad (CD-1) in the Colville River Unit, located at latitude 70° 20' 38", longitude 150° 55' 08", Prudhoe Bay, Alaska. This permit is subject to the conditions contained in Underground Injection Control Permit Number AK-1I003-A effective February 3, 1999, which is incorporated herein by reference, and to the conditions in the following paragraphs. The permittee must supply the Department with copies of the certified reports required in Underground Injection Control Permit Number AK-1I001-A, Section E, and "Reporting Requirements." Copies of the reports submitted to the U.S. Environmental Protection Agency must be sent to the following address: Alaska Department of Environmental Conservation 43335 Kalifornsky Beach Road, Suite 11 Soldotna, Alaska 99669 This permit is issued under provisions of Alaska Statutes 46.03, the Alaska Adnninistrative Code as amended or revised, and other applicable State laws and regulations. Any rights or privileges inuring to the benefit of the Environmental Protection Agency in the Underground Injection Control permit, including any right to enter, inspect, sample, and have access to records, also inure to the benefit of the Department. Any records or other information filed with the Environmental Protection Agency pursuant to the Underground Injection Control permit must be contemporaneously filed with the Department. This permit is effective on March 9, 2004 and expires at midnight, February 3, 2009. It may be terminated or modified in accordance with AS 46.03.120. Department regulations require that a wastewater disposal permit renewal request be received at least 30 days prior to the expiration of the current permit. Requests not received prior to this date cannot be renewed and must be reissued as a new permit. This process takes a minimum of 60 days, during which the facility may be prohibited from operating. Oran Woolley Wastewater Disposal Permits STATE ~F ALAS ~ H ~ DOMESTIC WASTEWATER PLAN. REVIEW/WAIVER/PERMIT FEE ~a'~ t r a d s 3 Invoice #223373 Department of Environmental Conservation -~ta~Rt~w # t3 PAYMENT IS EXPECTED AT TIME OF SUBMITTAL (please reference invoice # on your check) Make check payable to: STATE OF ALASKA ADEC contact: EIN 92-6600185 43335 Kalifornsky Beach Rd., Suite 11, Soldotna, AK 99669 DUNS: 809386587 A licants name:3Q~scE S E A plicants phone number: ~ ) ZGS ' ~~ t7 A licants address: ...- c o~t t t u. tP S En 'neer contact: Engineer contact hone number: ( ) Facility/Project Name: L ~t iv E C L Z V 1 C temtze invoice ount ~ eg - or a p an revtew wazver or an rant or oan a project, o not Reference make payment now. Please contact your azea ADEC office for information. Fee Amount code Due 72.440 ONSITE CERTIFIED INSTALLER i i $65 DW2C ng n Certified installer/homeowner tra $625 DW2C Certification fee - (2 years} Certification fee- (2 annual Instalhnents) - r' ~ - ' - ' $340 DW2C :~:. rrx r ~ ri~~ra ~ y '„-~ ~~,~ ~ ~ f .n $43/hr 72.945 INSPECTIONS LAN REVIEW (From Table D 5~~.1) ER 72.955 P DOMESTIC WASTEWAT 0 = 500 gpd f l $270 DW2R : ow o (A) Based on peak design f 501 - 1500 gpd f $340 DW2R : (B) Based on peak design flow o 1,501-2,SOOgpd f fl $360 DW2R : ow o (C) Based on peak design 501-15,000gpd 2 f ' $730 DW2R , : D) Based on peak design flow o ( 001-50,OOOgpd 15 f $1,200 DW2R , : (E) Based on peak design flow o 50,001-100,000 f l $2,370 DW2R : ow o (F) Based on peak design f 001-250,000 100 f $2,960 DW2R , : (G) Based on peak design flow o (Fi) Based on peak design flow of: 250,000 and over $3,510 DW2R 72.955 DOMESTIC WASTEWATER MODIFICATIONS TO AN EXISTING OR APPROVED DOMESTIC WASTEWATER SYSTEM THAT INCREASE DAILY PEAK CAPACTI'Y BY: Modification G20%; 20% of fee in A-H above DW2R Modification 20% to 50% change; fee is equivalent to percentage of that in A-H above DW2R Modification >50% change; fee is 100% of fee in A-H above sm~rr~env.~"c~-~r.-..Qra~,•s~raz.m~a~.~~.s- +~r~~r~.~ .-_~»n,. DW2R 1 ;+:m1:.,n 72.955 WAIVER/MODIFICATION OF PROVISIONS under 18 AAC 72.060 Individual on-site system (single-family or duplex) waiver(s) $300 DW2R First Five waivers submitted for a project, other than single-family or duplex $250/waiver DW2R `.`~ "r.-~ ~`y 72.955 NON-DOMESTIC WASTEWATER DISCHARGE PLAN REVIEW Does not include stormwater -Passive Treatment(2 or fewer treatment methods) $440 DW2R Each additional treatment method after 2 $90 DW2R Does not include stormwater-Complex Treatment (2 or fewer treatment devices) $940 DW2R Each additional treatment devtce after 2 $190 :""~""~~ *~~.-~u.. `'i''11.,a: ^-cr_7~'~Y^." ' -~~ . ' "' ' -~ . ~~ " ~ r' - ° ~e~--r,..~.-,7:.;:,e~~'^'~`.°"I}a"r.~"'~="~~i 72.955 ~ - r. . : .. " . . , .. .-,..i..,.~:....1 . n, rs ~ ~"+^S,7°'k-'"f'Z'+~"'° :.,~rr- -s.~.~x~i DOMESTIC AND NON-DOMESTIC(Iincluding Storm Drain collection) For sewer replacement, or extension of Up to 1,000 ft $310 DWZR per each additional 1 000 ft or fraction thereof $160 .u~~~i'~,I. ~LYs1W~'~~ _v.~i°,-'~`'. T' = _ rr ..r~ s'`11 '~ ' m~D•~ W2R '.'Y-c~~~.+:iy {1:...~..f:~6i~ 6 . ..._: . i~ . R.-a•1vi~. ... -. J..~.v...~r1 v~ .:, d GENERAL PERMIT-FIXED FEE TABLE E.1-11 use EH worksheet 72.95 Fee determined by Section # DW2GP 72.959 GENERAL PERMIT-HOURLY AND NEGOTIATED FEES -use EH worksheet Fee determined by Section # DW2GP 72.957 INDIVIDUAL PERMIT -FIXED FEE TABLE F.1-10 use EH worksheet Fee determined by Section # DW2GP 72.969 INDIVIDUAL PERMIT -HOURLY AND NEGOTIATED FEES-use EH worksheet Fee determined by Section # l~ ~ ~ G Z 2• • 959 DW2GP - J l d ~'~~ TOTAL: `~ l 8 C~~o Check # P 'd: ~ Cash .r.;aA Date Jl~'I13tUI Vl LL' vu~a~.. ---- -- **2nd and 3rd digit =region code, 4th, 5th, 6th digit =sequence number revised Sept. 2003 . . AOGCC Memorandum Date: August 3, 2007 To: DIO 18 AIO 18B v From: Jim Regg, Petroleum Engineer W14 0/3/0'7 Subject: Administrative Approvals DIO 18.001; AIO 18B.004 CP AI requested administrative approval to adjust the frequency of surveillance logging and plug depth tags ("surveillance") to be consistent with recent EP A action on the Class I disposal well WD-02 at Alpine. EP A recently relaxed the surveillance frequency to once every 2 years. I called MJ Loveland (CP AI, Well Integrity Project Supervisor; 907-659-7043) this date to clarify the frequency - their administrative approval request read "biannual". She stated the request should have read "biennial" (i.e., once every 2 years) instead of "biannual". Approval letters reflect the required surveillance frequency is "biennial". #4 · ~/ ConocoPhillips Alaska P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 May 6, 2007 Mr. Tom Maunder Alaska Oil & Gas Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Dear Mr. Maunder: · RECEIVED MAY 1 0 2007 Alaska Oil & Gas Cons. Commission Anchorage ConocoPhillips Alaska, Inc. presents the attached proposal to Modify DIO 18 to reflect the modifications that were made on the EP A class I injection well permit No. AK- 11003-A. The request is specially targeted to reduce the frequency of required wire line work to a bi-annual cycle. Administrative Action as described in Disposal Injection Order No. 18, Rule 6 would allow such changes based on sound engineering practices. There is no source of underground drinking water in this area therefore it is not endangered by this proposal and the reduction of required well work will reduce the risk of spills. If you need additional information, please contact me or Jerry Dethlefs at 659-7043, or Marie McConnell 1 Perry Klein at 659-7224. Sincerely, Ø0U MJ Leland Well ntegrity Project Supervisor ConocoPhillips Alaska Inc. Attachments . . ConocoPhillips Alaska, Inc. Alpine Well WD-02 (PTD 198258), DIO 18 Technical Justification for Administrative Action Request Purpose ConocoPhillips Alaska, Inc., proposes that the AOGCC approve this Administrative Action request as per Disposal Injection Order 18, Rule 6, to revise Rule 5 of this Order to reflect the Permit Modification ofEPA Class I Injection well Permit No. AK-11003-A, which reduces the surveillance logging and fill depth tag frequency requirement to not less than bi annual. Well History and Status Colville River Unit well WD-02 (PTD 198258) was drilled, completed, and permitted in 1999 as a Class I disposal well. It was also subsequently permitted via DIO 18 to allow Class II fluid injection. WD-02 and competed in the Ivishak and Sag River Formations. The perforated injection intervals are from 9459' -10047' MD. The well has primarily been used to dispose of wastes generated form oil production, maintenance operations, camp grey water system, and some fluids generated from drilling. This well has consistently demonstrated sound mechanical integrity (both internal and external) on an annual basis in compliance with the EP A permit and Disposal Injector Order requirements since injection was initiated in May 1999. The most recent MITIA was completed and witnessed by the EP A April 15 , 2007 Based on the historical mechanical integrity performance of the well, the EP A modified the class I injection well permit (No. AK-11003-A) Apri120, 2005, reducing the minimum frequency of required surveillance logging and fill depth tags to a bi- annual cycle. The required MIT IA frequency was not changed. Proposed Administrative Action To reduce risk from additional entry into the well and for consistency between the State and Federal permit requirements, ConocoPhillips requests a similar change to DIO 18 Rule 5 and suggests the following wording: Rule 5 Surveillance A baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to initiation of regular disposal injection. Regular fill depth tags and surveillance logging are required at least once bi-annually or as warranted following consultation with the Commission. Operating parameters including disposal rate, disposal pressure, annulus pressures and volume of solids pumped must be monitored and reported according to requirements of20 AAC 25.432. An annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, or survey results if completed, and volumetric analysis of the disposal storage interval, estimate of fracture growth, if any, and updates of operational plans. Report submission is due on or about July 1. Well Integrity Project Supervisor 5/8/2007 1 #3 AOGC Dill L<"?/ /J. 1/tf.}-/.J.s c ¡¿ ip r CondenseIt TM <'0 .:;LASKÞ. OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING 3 · In Rt,: ALPINE POOL TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska December 3, 1998 9:00 o'clock a.m. APPEÞ.R..LJ,¡,.:SS: 10 11 MR. DAVID W. JOHNSTON, CHAIRMAN MS. CAMI LLE OECHSLI MR. ROBERT CHRISTENSON 12 MR. MR. MR. MR. MR. MARK IRELAND DOUG KNOCK MICHAEL D. ERWIN DOUGLAS K. CHESTER BRIAN RI CHARDS Ine. : 13 14 15 16 17 18 19 f" r Z1"" , I: V Î-.~ Dr w ;;~. 20 21 1Q9~ n '.J 0 22 23 Cmmr:iSSlun }/, ,.,,, 24 25 · PRO C E E DIN G S - - - - - - - - - - - record - 9:05 a.m.) 3 ~:HAIRHAN JOHNSTON: Well r good morning. It r s a real 4 pleasure have everybody here today. I'd note the time is 5 appr,")x C;l('L five after nine 0' clock, the date is December the ",,-, -" 6 3r.-d. j and we are located in the offices of the Alaska oil 7 and >rls'2rvation Commission, located at 3001 Porcupine 8 Dri-,·''''' Aneh'::Jrage, Alaska. The head tables consists of myself, Dave Johnston, and to my right is Commissioner 10 Cammie and to her right is commissioner Bob 11 ChrL tens-=-,f These proceedings today will be recorded by Laura 12 Fee: Court Reporting. If you wish to receive a 13 tr·:ülsc!~-ip::. ~,-f these proceedings, we'd ask that you contact 14 Metre directly. 15 proceedings are to consider an applied tion by 16 ARCO IÜask¿t define and establish pool rules for the Alpine 17 Oil P-c:l. ,ole are also here to hear testimony to consider an 18 order injection order authoring underground disposal in 19 the area. 20 e·:xnrnission published notice of the hearing in the · 21 Ancll:).t>lqe C·aily News on October 16, 1998, and for the injection 22 projecc November 3, 1998. 23 hearing will be conducted, as usual, according to 24 commi :",i:)l', regulations, 20 MC 25.540. Those briefly allow us 25 to expert testimony. If you wish to be considered an MetN Cewt Reporting, Inc. Page 2 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 c Cj ~3 RE: Alpine Oil Pool Page 3 expert, of course we'd ask that you state your qualifications, and the commission will render a decision or a determination as to whether we will consider you an expert in this matter or not. We will not necessarily allow questions from the audience. If you do have questions though, we'd ask that you write your questions on a piece of paper, get it up to the front table here. If we feel it is germane then the commission may consider asking that question of the applicant. And I'd encourage you to do that at any particular time. You can motion or somehow get the note up to us and we can take a look at it at that time and make a determination. If not, we'll be taking periodic breaks throughout the morning and that will also provide an opportunity to get questions to us. So I guess with that brief introduction I would like to ask the spokesperson for ARCO Alaska to identify themselves and 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 ARCO 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. 1 2 3 4 5 6 7 8 9 10 II 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 4 CHAIRMAN JOHNSTON: Before you proceed, Mark, since you will be providing technical testimony, do you wish to be considered as an expert witness and to offer sworn testimony? MR. IRELAND: Yes, I guess I should be. CHAIRMAN JOHNSTON: Let me go ahead and swear you in and then you can proceed with your testimony. If you'd raise your right hand, please? (Oath administered) MR. IRELAND: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself sworn. MR. IRELAND: Thanks. CHAIRMAN JOHNSTON: please proceed. MR. IRELAND: okay. First of all, I'd like to talk about the name of the pool in the field we're involved with today, and hopefully I won't trip over this too badly. But there's been a number of different names incorporated in the past. This is known as the Colville, also as Alpine, and Alpine is the name that we're using for the reservoir section today. The Colville River area is the geographical area where we're located. The Colville River Unit is the official unit name that's been approved for the Colville River Unit, and within the Colville River Unit we'll be forming an Alpine participating area sometime next year. So in order to maintain consistency in our application for the pool rnles, we're naming Page 1 - Page 4 · · · AOGC . CondenseIt TM Page 5 1 the field after geographical area, the Colville River field, 2 and naming the pool after the reservoir, Alpine Oil Pool. 3 As ¡mentioned, I'll cover the introduction and any 4 swmuary 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 swmuary 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'l1.be supplying testimony today in 17 support of all the rules that we'll propose in this area -- in 18 these areas. 19 20 21 22 23 24 25 Our top priority with the Alpine development, we'll be protecting the health, safety of human resources as well as the environment while we're conserving the Alpine resources. These proposed pool rules will prevent waste and promote conservation. They will allow to protect correlative rights and promote maximum, ultimate recovery. Some brief background on the history of drilling in the Page 6 1 Alpine area. The field was discovered in 1994 with Bergschrund 2 Number t well. In 1995 we drilled five wells, including side 3 tracks. the Alpine Number 1, I-A and I-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 tì'om the ultimate pad locations. Those are the C01-22 8 well and the CIJ2- 35 well. 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 The ownership in the field. The royalty owners, the State of Alaska. as well as the Arctic Slope Regional Corporation. On the working interest side, ARCO Alaska Incorporated. with 56%, as well as controlling the 22% that Union Texas Alaska owns, along with Anadarko Petroleum Corporation with 22%. So effectively ARCO controls 78% of the working interest. With that brief introduction, if there aren't any questions. I'll turn our testimony over to Doug Knock, who will speak to the geology. CHAIRMAN JOHNSTON: If you'd like to raise your -- I assume you wish to offer sworn testimony? MR KNOCK: Yes, I do. CHAlRMAN JOHNSTON: Raise your right hand, please. (Oath administered) MR KNOCK: I do. CHAIRMAN JOHNSTON: consider yourself sworn. Do you Metro Court Reporting, Inc_ . RE: Alpine Oil Pool Page 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? 11 COMMISSIONER OECHSLI: NO objection. 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 trias sic 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 Page 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? 11 MR. KNOCK: The commercial limits, as we believe them 12 to date, fall within the hatchered pattern. 13 CHAIRMAN JOHNSTON: okay. 14 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 areÆI. Only the Alpine 19 sandstone has been found to contain commercial quantities of 20 hydrocarbons to date. 21 CHAIRMAN JOHNSTON: IS there any -- have you discovered 22 any Ivishak? 23 MR. KNOCK: There's two penetrations of the Ivishak in 24 the Colville River Unit, and it is very high water saturation, 25 perhaps 75% and greater water saturation in the Colville River Page 5 - Page 8 · · · AOOC . CondenseIt 1M Page 9 1 unit. 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: And where would you put the Ivishak generally on this? MR. KNOCK: oh, it's Triassic, it's about 1000 feet below the Nechelik. I've got a diagram later that will show that. Pool rule number 2. The Alpine 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. CHAIRMAN JOHNSTON: And would you point that out again for the benefit of..... MR. KNOCK: I will. CHAIRMAN JOHNSTON: .....the audience? MR. KNOCK: I've got a diagram right here that is an Alpine oil pool type log from the Bergschrund 1 well. The Alpine pool is shown to the left of the diagram. It is bracketed on the top by the top Alpine pick, based on gamma ray and resistivity logs, and on the base by the Kingak E marker, also based on ganuna ray and resistivity. Alpine is a quartz rich. very fine defïned grain sandstone, very well sorted -- well sorted and locally glauconitic. CHAIRMAN JOHNSTON: on your Exhibit 3, if you could flash that up? MR. KNOCK: uh-huh, put that back up. It's right here. Page 10 1 CHAIRMAN JOHNSTON: IS this your pool limits from this 2 point to where,..... 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. KNOCK: Yes. CHAIRMAN JOHNSTON: .....up there? MR. KNOCK: Yes, from the marker you pointed to, to the marker right above where it says Alpine sandstone, down to the marker below that is the same as Exhibit 4, correct. CHAIRMAN JOHNSTON: Thank you. MR. KNOCK: This is a top Alpine structure map. Alpine is largely a stratigraphic trap with up-dip pinch-out to the northeast. Northeast being here. Pinched out into shales of the Kingak. The faults are generally northwest trending, generally down to the west nomlal faults with small throws .- small offsets averaging 20 to 30 feet. No oil·water contact or gas·oil contact has been found in the field to date. And that concludes my Alpine oil pool discussion. CHAIRMAN JOHNSTON: Let me ask you a few questions. If you could put Exhibit 5 back up on the screen? What do you know about these faults that cut through the area? MR KNOCK: They're pretty small in offset. Alpine is -. ranges in thickness from 20 to over a hundred feet. Generally the 20 to 30' kind of offsets we're not really concerned about as being major barriers to flow. These faults cut down through the Sag River marker which is an excellent seismic retlector, about 1000 feet below Alpine. They are a Metre Court R.eporting, Inc. . R.E: Alpine Oil Pool Page 11 I 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 nortbeast..... 17 MR. KNOCK: Northeast, largely onto a structure 18 generally known as the Colville high -- towards the Colville 19 high. 20 21 22 23 24 25 CHAIRMAN JOHNSTON: so what kind of dip are we talking about in this area? MR. KNOCK: very gentle, one to two degrees dip to the south and southwest. CHAIRMAN JOHNSTON: Thank you. MR. KNOCK: I've got a little bit to say on annular Page 12 1 disposal geology now. We plan to set surface casing at 2350' 2 subsea TVD at Alpine. And below that will be open annulus down 3 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. 11 Next is a diagram showing some of what I just talked 12 about. This is annular disposal type logs, the Bergschrund 1 13 well. See, surface casing is right there in red. That's at 14 2350' subsea. Below that is the Seabee formation of shale wall 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 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 particular well is down to 850'. 25 CHAIRMAN JOHNSTON: what do we know about water quality Page 9 - Page 12 · · · AOGC . CondenseIt 1M Page 13 1 in this area') 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR KNOCK: The total dissolved solids by the log measurements we have done are 10,000 parts per million and greater. based on our petrophysicist looking at several points below permafrost on down into the Torok. So generally that's unpottable. briny water, if you will. There's no drinking water present. CHAIRMAN JOHNSTON: And what has been your experience to date with annular disposal? MR KNOCK: JUst my knowledge of ARCO's other operations on the Slope with annular disposal. I know what they're doing at the Tarn location..... CHAIRMAN JOHNSTON: so you don't have any personal knowledge about annular disposal in this immediate area as to hO\\ it's gone for you, your success in putting fluids away, that sort of thing? MR. KNOCK: TO my knowledge in the Alpine pool area we have not done annular disposal. CHAIRMAN JOHNSTON: I guess we've authorized it but you haven't actnally done it yet, that's right. Okay. MR KNOCK: That's correct. CHAIRMAN JOHNSTON: okay. Thanks. MR KNOCK: NOW I'm going to touch on Triassic waste injection disposal briefly. In this coming February we will drill the waste disposal #2 well. It's a Class 1 industrial Page 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 ['ve got a diagram coming up that shows that. First 7 here's the location of the disposal well on a top Sag River 8 structure map. The well is 2500' or so from the Colville Delta 9 pad I. 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 14 15 16 17 18 19 20 21 22 23 24 25 it is over at Prudhoe Bay, much lower porosity -- 16% average porosity. 400' of gross sand. Above that is the Shublik limestone. we consider that to be a barrier, and above that is the Sag River sandstone which we're calling our upper injection zone. averaging about 19% porosity, and 35' of net sand. Then the Kingak shale. we've divided it into 700' of arresting zone and 400' of confining zone, prior to hitting the upper Jurassic Nechelik sandstone. CHAIRMAN JOHNSTON: Let me explore with you some of the terms that you're using here. Why are you calling this an arresting zone: what's your logic there? MR KNOCK: we think that that shale, at a minimwn, slow down the growth of a vertical fracture. It's 700' thick. Metro Ceurt Reporting, Inc. . RE: Alpine Oil Pool Page 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..... 9 CHAIRMAN JOHNSTON: The Ivishak interval's 79' thick. 10 MR KNOCK: That's 79' ..... 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 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 porosity, and we will see how that goes, see what that will do later. We may have to go in and add perfs and potentially add perfs to the Sag River. But that's a thick shale, the Kingak 1100'. Like I said, I don't anticipate a large vertical fracture extending up into the Jurassic sands. CHAIRMAN JOHNSTON: so would you describe the Shublik that you currently labeled as a barrier, would you describe that as a confining zone for the lower injection in the Ivishak? MR. KNOCK: Limestones are pretty competent. They'd be Page 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 playa 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 Page 13 - Page 16 AOGC . . CondenseIt TM Page 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 CHAtRMAN JOHNSTON: The faults that you showed on your 4 structure map, I don't see the exhibit mUllber, but the one 5 ilmllediately before that...... 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 · · · MR. KNOCK: Before this one? CHAIRMAN JOHNSTON: DO those faults cut up through the entire stratigraphic column? MR. KNOCK: A lot of them do. A lot of these faults cut on up through the Alpine interval. They decrease in throw as they go up section. At this level they're -- a lot of them are 50' average offsets, and then at the Alpine level 20 or less in some cases, Actually there's more faults here so there's some that do not cut up, but some of the major ones do. CHAIRMAN JOHNSTON: so that your point of disposal 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. CHAIRMAN JOHNSTON: .....from your known fault, and that's at your point of disposal? MR. KNOCK: That's correct. This is -- the scale of this map. one inch is equal to 5000. that's approximately half an inch or a third of an inch to that fault, it's well over 1000' to that fault, perhaps 2000, looking at that scale. We've looked at the seismic and don't see any -- any large Page 18 1 faults that -- ór 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 I"vel that well would draw (Ph) right about there to the east 6 of pad I. 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 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: so that may be an example of a fault that does not necessarily..... MR. KNOCK: Right. CHAIRMAN JOHNSTON: Thank you. MR. KNOCK: Thank you. MR. IRELAND: Hello. I'm Mark Ireland once again, and I'll be discussing the reservoir section of our testimony today. CHAIRMAN JOHNSTON: And I assume you wish to be considered an expert witness? MR. IRELAND: Yes, that would be appropriate. CHAIRMAN JOHNSTON: If you'd like to state your qualifications for us? MR. IRELAND: certainly. I have a bachelor's and master's degree in petroleum engineering from Penn State University. I've worked with -- for ARCO for over 15 years in various Lower 48 locations. In the last 5 or so years in Metre Ceurt Reporting, Inc. RE: Alpine Oil Pool Page 19 1 Alaska, working on Prudhoe Bay, Pt. Mac, Lisburne, and Alpine 2 fields. 3 CHAIRMAN JOHNSTON: Thank you. Any objection? 4 COMMISSIONER CHRISTENSON: NO objection. 5 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 Page 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 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 Kuparnk 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 11 over a 30-year or so lifetime of -- from 35 to 45% recovery 12 basically with the downside lower injectivity waterflood case 13 giving the poorest recoveries and upside waterflood perfonnance 14 with the gas re-injecting -- re-injection, giving one of the 15 highest recoveries. 16 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 l60-acre spacing. Page 17 - Page 20 AOGC . CondenseIt 1M Page 21 . · 1 The second phase being the peripheral area, that area 2 between a peuneability thickness of 600 alt- -- 200 millidarcy 3 feet. There would be 42 wells drilled in that part of the 4 field, They would be all vertical wells on 160-acre spacing. 5 The plan would be to inject water and watertlood the core area 6 and utilizc 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 l40-acre spacing. If you remember for 19 the current plan, that's 275-acre spacing for the horizontal 20 wells. and now we've also got all wells in the core area 21 horizontal versus originally part of those -- some of those 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 · Page 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 n 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, Metre Ceurt R.eporting, Inc. lŒ: Alpine Oil Pool Page 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 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 or..... MR. IRELAND: That would be a part of it, but it's more technical studies that need to be completed, then followed by further economic analysis, and then gaining the approvals that I mentioned. CHAIRMAN JOHNSTON: okay. When do you anticipate completing these technical studies? MR. IRELAND: we hope to have the new plan of development -- of course the current economics in the industry are not as favorable as they were previously, but if everything works out well, and hopefully by next summer we could have a new plan of development in place. CHAIRMAN JOHNSTON: And I assume it would be your intent to present this to the commission? MR. IRELAND: certainly. CHAIRMAN JOHNSTON: Thank you. Oh, one more question. In terms of your current development plan, what type of time Page 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 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CHAIRMAN JOHNSTON: so is..... MR. IRELAND: .....or the current plan. CHAIRMAN JOHNSTON: IS that to drill all the wells under both Phase I a.nd Phase II? MR. IRELAND: Right. Approximately five years. CHAIRMAN JOHNSTON: okay, then what's the logic then in presenting it as a Phase I, Phase II option? MR. IRELAND: JUst that the first phase would represent what we would expect to be the best perfonning wells in the field, so that would be where we would concentrate our initial -- will concentrate our initial drilling. CHAIRMAN JOHNSTON: so how long..... MR. IRELAND: The second phase is as you get out to the boundaries of the field it has the poorer quality rock, the lower KH, as well as those are more expensive wells as you get farther away from the drill site. So the economics of those wells are not as finnly established as they are in the core area -- Phase I core area. CHAIRMAN JOHNSTON: so what then is your time line on Phase 1 ? Page 21 - Page 24 CondenseIt 1M Page 25 1 MR. IRELAND: phase I would probably take approximately 2 three years to drill all of those wells. 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOOC . · CHAIRMAN JOHNSTON: And then your Phase II then? MR. IRELAND: Another two years or so. CHAIRMAN JOHNSTON: Another two years beyond that? MR IRELAND: Yeah. CHAIRMAN JOHNSTON: And would those same time lines apply for the proposed revised plan? MR. IRELAND: with the greater number of wells, the time line would be expanded to drill all the wells in the development plan. CHAIRMAN JOHNSTON: And so you wouldn't necessarily have additional drill rigs? MR IRELAND: Not necessarily, no. CHAIRMAN JOHNSTON: But of course it is an option, I guess? MR IRELAND: could be an option, yes. CHAIRMAN JOHNSTON: okay. Thank you. MR. IRELAND: sure. As we continue to study the opportunity for a revised plan of development, we're also looking for further optimization beyond that plan, and some of which will be evaluated here in the coming year with some of our first wells in the field. Multiple target wells are one of the first areas and the opportunity here is to develop more of the reserves of the · Page 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 9 with the multi-lateral well, and that would be a well that 10 penetrates the fonnation and then kicks out in one direction 11 down the line and then comes back and kicks out in the other 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. 15 Infill drilling, something that is continued to look 16 at. and that's really one of the key components of the revised 17 plan of development is the infill drilling, going from 3000' 18 interwell spacing to 1500'. 19 And then miscible injection optimization, assuming we 20 gain sanction for the miscible project, then the optimization 21 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 Metre Cettrt Reporting, Inc. (. RE: Alpine Oil Pool Page 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? 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..... 19 MR IRELAND: NO, you're talking about a couple hundred 20 cubic feet per day versus the millions of cubic feet that we'll 21 be producing. 22 CHAIRMAN JOHNSTON: so that would just be for purposes 23 of maintaining pressure in the reservoir, you wouldn't -- 24 there's no -- under the current development plan there's not 25 necessarily a hard proposal for miscible flood. Page 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, 1'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. Page 25 - Page 28 AOGC . CondenseIt TM Page 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 infonnation on those. 5 On spacing units, because of the geometry of the 6 horizontal wells we're drilling, we're asking for no minimlUTI 7 spacing. although not closer than 500' from ownership changes 8 at the boundaries of the pool. 9 On Ihe GOR limitation, we're asking for an exemption 10 from producing GOR limits, and I'll show a little more 11 inforulation on each of these requests. The potential to nœd 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 nœd to isolate high 16 permeability zones to manage our off-take of our flood, and 17 also may nœd 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 · Page 30 · 1 as welL 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 That concludes my testimony for the reservoir section. I'd be happy to answer any other questions. CHAIRMAN JOHNSTON: Thank you, Mr. Ireland. I don't think the commission has any questions currently for you, although we may have later. MR. IRELAND: Great. I'll turn it over then to Doug Chester, who will cover the drilling section. MR. CHESTER: GOod morning. CHAIRMAN JOHNSTON: GOod morning. Do you wish to offer sworn testimony today? MR. CHESTER: Yes, sir. CHAIRMAN JOHNSTON: If you'd raise your right hand please. (Oath administered) MR. CHESTER: I do. CHAIRMAN JOHNSTON: Thank you. Consider yourself sworn. 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 drilling team leader with ARCO oil and Gas -- excuse me, ARCO Alaska Incorporated. I received a bachelor of science degree from Texas A & M in 1980. I've worked 17 years in the industry. with experience in Texas, Louisiana, Oklahoma, Metre Ceurt Reporting, Inc. RE: Alpine Oil Pool Page 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 ARCOIBP 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. 9 CHAIRMAN JOHNSTON: Thank you. Any objections? 10 COMMISSIONER CHRISTENSON: NO objection. 11 COMMISSIONER OECHSLI: NO objection. 12 CHAIRMAN JOHNSTON: Thank you, Mr. Chester. The 13 commission will consider you an expert witness in this matter. 14 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 minimlUTI 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. Page 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 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Continuing on, we will use what we call a "blUTIp and run" well design. This will mean that in our intermediate section we will drill through the Alpine reservoir, as we're going to, horizontal. This will give us a top and bottom pick of the reservoir when we drill it. We will set the intermediate casing in the Alpine zone at horizontal or very close to horizontal. We will perfonn fonnation integrity tests in the zone. We will drill our horizontal section, swap out our drilling fluid to a diesel, and leave an open hole completion. We will then run our tubing, is the current plan. Our plans for surveys will be with MWD tools. Logging will be with LWD in the zone. Current logging practices, drill pipe conveyed in those type will be used as needed, but at present the plan for logging will be with LWD, due to the horizontal nature of the wells. We plan to batch drill, and this is to reduce material storage, so at anyone time we may be drilling a group of five or six surface holes, moving the rig off and coming back and completing the wells at a different time. With the remote nature of the site, this is an attempt to kind of reduce our footprint and reduce the amount of Page 29 - Page 32 AOGC . CondenseIt 1M Page 33 . RE: Alpine Oil Pool Page 35 1 material needed to be stored at the location. 1 and we would propose being granted that under drilling 2 We plan on using a single BOP rig-up. This will be 2 permitting process. . 3 done by a through bore wellhead system, and our horizontal 3 Our C proposal is we would like to request going to a 4 wellhead system will enable us to nipple up BOPS without -- and 4 two week BOP test period. Our reason for asking this is our 5 do work-overs without nippling down flow lines and our wellhead 5 current time lines show that in the intermediate drilling plans 6 system. 6 we come to casing point right about seven days in the Alpine 7 Mud systems for the wells are typical North Slope 7 time lines. What this request would allow us to do is go ahead 8 systems. and we propose no major changes in the mud. 8 and run our casing at a very critical time in the well, not 9 COMMISSIONER CHRISTENSON: HOW are you going to leave 9 having to stop and do BOP tests or continually ask for waivers. 10 the wells in the (indiscernible)? 10 We would hope that we could do this under a field rule request. 11 MR. CHESTER: we plan on leaving the wells at the 11 On the D part listed, we are requesting that we submit 12 surface casing point. If we suspend at that place, we will 12 under the Application to Drill to include a Plan D vertical 13 essentially bump our cement plug, do a pressure test on that 13 section close approach, that and directional description. This 14 string of casing. We will set our wellhead system, install a 14 will be essentially a reduction of paperwork between us and the 15 back pressure valve, and essentially, what I'll call a dryhole 15 commission. These wellbores will be in the unit, and we feel 16 tree. which consists of a master valve left on the tree. So it 16 like this will enable you to have the information you need 17 will be essentially secured. The same type of abandonment (Ph) 17 without undue additional paperwork. 18 would be used if we stopped and suspended an intermediate 18 Our additional request is a complete electrical log and 19 casing point. The only difference would be you'd have the 7" 19 radioactivity log will be required below the conductor to TO 20 casing versus the 9 , but both casing strings would be tested 20 for only one well on each drilling pad. This has been somewhat 21 with a pressure test, verified that they're competent, set a 21 of a current practice. We have fulfilled this obligation on 22 back pressure valve in the wellhead, and the wellhead surface 22 our first drill site with the 1-22 well. We would propose that 23 valve would be on the tree. 23 we do this when we go over to the second drill site, provide 24 COMMISSIONER CHRISTENSON: Thanks. 24 the conunission with a full suite of logs. And once that is met . 25 MR. CHESTER: we have provided data to the EPA in our 25 we will supply reservoir type logs but not log service Page 34 Page 36 1 Class I pcnuit that we have no USDWS in this area, and there 1 holclintermediate hole unless it's -- there is a technical 2 was some discussion previous to that determination in earlier 2 reason to do so. 3 testimony, We will have a ball mill capable of grinding and 3 We also request and submit that we're providing 4 washing gravel on location. This is -- the proposed plan is to 4 sufficient and appropriate disposal intervals at Alpine, or 5 wash gravel. recycle it, use it as maintenance gravel, and then 5 have showed those. We would like to work under 25.080 for 6 inject through annular injection our wellbore muds cutting 6 annular injection, and we would like to essentially tell the 7 fluids that were not recyclable. 7 commission that we plan to use a particular well for annular 8 The injection zone, as has been discussed earlier, is 8 injection, and hopefully under the pool rules we have 9 to top the Seabee, the combining zone at Schrader Bluff, and we 9 demonstrated that annular injection is a viable injection 10 have approximately 1000' below the West Sak. 10 process at Alpine. 11 Our pool rule request under Rule 4, we have requested 11 CHAIRMAN JOHNSTON: why shall we not require more log 12 that upon drilling out no more than 50' into the Alpine 12 data than what you're proposing under D? 13 reservoir that we provide a formation integrity test, and the 13 MR. CHESTER: with the Alpine reservoir -- or excuse 14 test pressure will not exceed a predetermined mud weight 14 me, with the close spacings and the general area we feel like 15 supplied in the drilling permit application. The reason for 15 the one that is required will give us a baseline for whatever 16 this is we don't want to create a fracture at the casing shoe 16 is needed. We haven't seen a lot of other reasons for 17 that could cause production problems or injection problems in 17 additional logging up in the hole, as far as other horizons or 18 the future. This will determine that we have a competent shoe 18 any of those type of opportunities. 19 and enable us to drill in the reservoir with a known pressure. 19 CHAIRMAN JOHNSTON: In terms of -- how large an area of 20 Our second request is we would like to be able to be 20 the reservoir can you -- will you be developing from -- I guess . 21 granted administratively completion and casing design program 21 you're only using two pads, right? 22 changes. We believe the open hole in the slotted liner 22 MR. CHESTER: Yes, sir, that is correct. 23 completions that are proposed are the best completions at this 23 CHAIRMAN JOHNSTON: SO you're going to develop the 24 time. But with new information and in continued drilling there 24 entire reservoir from two pads? 25 may be other technologies that we will need to test and try, 25 MR. CHESTER: That is our plan. Metre Cewt Reporting, Inc. Page 33 - Page 36 CondenseIt 1M Page 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. 12 COMMISSIONEROECHSLI: DOug, would you mind putting the 13 earlier slide up again? 14 MR CHESTER: which one? 15 COMMISSIONER OECHSLl: 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 20 21 22 23 24 25 AOOC . · was..... MR CHESTER: Did we miss A, B, C,..... COMMISSIONER OECHSLl: .....left out, but it's not. MR CHESTER: .....07 COMMISSIONER OECHSLl: NO, it's just all there, just a different.... . · MR CHESTER: I'm sorry. Page 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 con-elation 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 TO-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 TO 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 MetN Ceurt Reporting, Inc. . RE: Alpine Oil Pool Page 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 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 we would probably do. The fact is that it's going to be a very continuous type operation if we don't do this. So that's the reasoning. CHAIRMAN JOHNSTON: And if we don't allow this waiver 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 OECHSLl: only if the waiver is not granted, right? MR. CHESTER: That is correct. CHAIRMAN JOHNSTON: But there is nothing to prevent you from testing your BOPS earlier? MR. CHESTER: That is true. And kind of the way it breaks down right now, that would be like four days in with how we would drill Alpine and how we have seen in the past is we will only make one trip before TO. In other words, we'll put a bottomhole assembly in the hole and we'll drill to our kick-off point. We will trip, we would have to test that, and that's roughly a four-day interval. So the timing is what -- we'd either have to test it there or test it at TO. Those would be the times of our trips. In the optimized drilling world, so to Page 40 1 speak. 2 CHAIRMAN JOHNSTON: Thank you. 3 COMMISSIONER OECHSLl: DOug, could you clarify for me 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 OECHSLl: 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 OECHSLl: .....(indiscernible- 24 simultaneous speech) and the volumes? 25 MR. CHESTER: .....done -- well, those are done after Page 37 - Page 40 AOGC . CondenseIt 1M Page 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 HT 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 infonnation at once 24 for annular injection at Alpine, and then just submit to you 25 the competence data that you need to detennine that this well · Page 42 1 can be used for annulaI' 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. That was the only reason for my hesitancy. 9 CHAIRMAN JOHNSTON: DOeS that conclude your testimony 10 then? · 11 MR. CHESTER: Yes, sir. 12 CHAIRMAN JOHNSTON: Any further questions? 13 COMMISSIONER OECHSLI: Not at this time. 14 COMMISSIONER CHRISTENSON: Did you guys get this in 15 your enclosure? 16 COMMISSIONER OECHSLI: NO, but it is included in the 17 18 19 20 21 22 23 24 25 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 Doug Chester. and it appears that Mr. Erwin is in the hot seat. MR. ERWIN: Yes, sir. Metre CMØt It.epørting, Inc. . RE: Alpine Oil Pool Page 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 Page 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, 6 " diameter bit, over approximately 3000', as we've 10 described in our development plan. We'll have 16" conductor, 11 9" surface casing. 7" production casing will be directionally 12 drilled to achieve a horizontal set point within the Alpine 13 fonnation. 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 Page 41 - Page 44 AOGC . CondenseIt 1M Page 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 n whatever reservoir problems or challenges develop as we 17 drill up the field. 18 Examples -- oops. Excuse me. Examples of some of the 19 COlmnon 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 · Page 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 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Those lines are roughly to scale, and I think that you'll see that from a spacing standpoint we can't deviate too broadly from the existing spacing patterns without negatively impacting the overall waterflood patterns and is a primary reason why we're asking for the no minimum spacing requirement. CHAIRMAN JOHNSTON: Are you going to be plugging back on those before you do the sidetrack or..... MR. ERWIN: I think it will depend on the situation. There could be opportunities where you would enlarge your injection area, for instance, by leaving the original open hole there. Certainly if it's to avoid conductive faults or directional penneability changes, we would probably cement the wellbore out. Reservoir Surveillance, as a topic, is covered in Rule 5. We're recommending initial static bottomhole pressure be taken in all of the Class II injection wells. That would represent approximately half of the total wells drilled and would be our best source of initial static bottomhole pressures. We envision an extended drilling period that would allow for those initial statics to be taken throughout the initial development of the field. We're requesting a minimum limit of six statics per year, and that's because of the MetM Cewt Iteporting, Inc. RE: Alpine Oil Pool Page 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 datmn 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' datmn 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 Page 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 ban-els per day and 5,000,000 cubic fæt of gas. 19 CHAIRMAN JOHNSTON: would those wells be capable of 20 unassisted flow to the surface? 21 MR. ERWIN: Yes, sir. 22 CHAIRMAN JOHNSTON: They still would. 23 MR. ERWIN: For a very brief time it would be possible. 24 CHAIRMAN JOHNSTON: what do you consider a very brief 25 time? Page 45 - Page 48 CondenseIt TM Page 49 1 MR. ERWIN: I would expect hours not to exceed 24 until 1 2 the well is loaded up. 2 3 An automatic fail closed injection valve, which is not 3 4 surface controlled, would be installed in injection wells as a 4 5 subsurface safety valve with testing conducted on an annual 5 6 basis. 6 7 CHAIRMAN JOHNSTON: How are you going to be freeze 7 8 protecting the wellhead and the corresponding surface safety 8 9 valve equipment? 9 10 MR. ERWIN: Freeze protection on the producers will 10 11 consist of a kill weight brine with a diesel cap. The diesel 11 12 cap would be the freeze protection. We're looking at using 12 13 nitrogen perhaps on the injection wells. If not it would 13 14 either be diesel or a nitrogen cap on the injection wells. 14 15 CHAIRMAN JOHNSTON: I guess my question was not how 15 16 you're going to freeze protect the wells from the effects of 16 17 permafrost, but are you going to freeze protect the wellhead so 17 18 the surface safety valves -- you know, the pilots, the lines 18 19 and that sort of thing, do not freeze up? As I understand -- 19 20 are you going to have dog houses around these wellheads? 20 21 MR. ERWIN: Yes, sir. 21 22 CHAIRMAN JOHNSTON: okay. So they will be enclosed? 22 23 MR. ERWIN: Excuse me one moment. Brian, are you able 23 24 to hear that? 24 25 MR. RICHARDS: Yeah. Do you want me to talk about 25 · · · AOGC . Page 50 1 that? 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. ERWIN: If I could defer that to Brian Richards...... CHAIRMAN JOHNSTON: That would be fine. MR. ERWIN: It's specific -- it will fit better in his area. David. CHAIRMAN JOHNSTON: Right. MR. ERWIN: were there any other questions in this area? COMMISSIONER CHRISTENSON: NO. MR. ERWIN: I'd like to briefly address the Class II injection well completion. This is the Sadlerochit disposal well. We would again be setting 16" conductor, 9 " surface casing here would be set slightly deeper than the producing wells. We would be running a 7 by 7" production casing string to n and the tapered string is to provide for the thaw protection in the -- through the pennafrost. Heat tracing. An 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 Metre CMrt Ileporting, Inc. . RE: Alpine Oil Pool Page 51 may be best again for Brian, but let me put it out there anyway. How would you describe the surface environment in this particular location? I mean part of my concern, relative to removal of subsurface safety valves, would be, you know, the sensitivity of the surrounding environment. Clearly commission regulations recognize the importance for the offshore environment, and we have a requirement that subsurface valves be installed. But onshore it's a different matter, there's no finn criteria to require subsurface safety valves. It's bœn commission practice, however, to require them in sensitive areas. And the Colville Delta, I think in everybody's consideration, is relatively sensitive environmentally speaking, and an area that should deserve highest protection. So I note that you are in fact proposing subsurface safety valves as a routine matter. MR. ERWIN: Yes, we are. CHAIRMAN JOHNSTON: But you do wish to remove them at your discretion in these, I guess you described it as marginal wells? I guess again I'm thinking what -- even though the well may flow for a short period of time, what steps are you taking to ensure that if there was a failure of the wellhead is there any containment on the pad being proposed or how do you -- what further steps are being taken to ensure that we don't have a spill getting out into the waterways of the Delta and such? MR. ERWIN: That's a very good question. It would be Page 52 1 best to defer that to Brian, who can address the facility and 2 surface. 3 CHAIRMAN JOHNSTON: Thank you. 4 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 MR. ERWIN: Yes, sir, I do. We expect to see very 8 rapid -- once the waterflood fronts do break through we'll see 9 very rapid increases in the watercuts on the producing wells. 10 COMMISSIONER CHRISTENSON: okay. Thanks. 11 CHAIRMAN JOHNSTON: Mr. Richards. 12 MR. RICHARDS: Good morning. 13 CHAIRMAN JOHNSTON: And I assume you wish to offer 14 sworn testimony? 15 MR. RICHARDS: Yes. 16 CHAIRMAN JOHNSTON: If you'd raise your right hand, 17 please. 18 (Oath administered) 19 MR. RICHARDS: Yes, I do. 20 CHAIRMAN JOHNSTON: Thank you. Consider yourself 21 sworn. Do you wish to be considered an expert witness? 22 MR. RICHARDS: Yes. 23 CHAIRMAN JOHNSTON: please state your qualifications. 24 MR. RICHARDS: I graduated from Iowa State University 25 in 1977 with a bachelor's degree in chemical engineering. In Page 49 - Page 52 AOGC . CondenseIt TM Page 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 operations representative on the Alpine Project Team. 8 CHAIRMAN JOHNSTON: Thank you. Any objection? 9 COMMISSIONER OECHSLI: NO objection. 10 COMMISSIONER CHRISTENSON: NO objection. 11 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 22 down -- it comes right over here by the village of Nuiqsut, and 23 then eight miles down river is where all of our facilities of 24 the field will be built, right here. 25 In this little circle blow-up over here you can see we · Page 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 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 Metre c..t lteporting, Inc. RE: Alpine Oil Pool Page 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 infonnation 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 platfonn system at CPF-2, Page 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 Page 53 - Page 56 Cond.enseIt TM Page 57 1 main inlet separator where all the production fluid is going 1 2 into and it's slightly smaller than a Kuparuk vessel, but not 2 3 very much. It's going to have -- it's a compact plant but it 3 4 has large equipment. 4 5 COMMISSIONER CHRISTENSON: what does it weigh? 5 6 MR. RICHARDS: what's that? 6 7 COMMISSIONER CHRISTENSON: what does it weigh? 7 8 MR. RICHARDS: The vessel itself, I'm not sure. The 8 9 biggest module we have is roughly 1200 tons. 9 10 In the gas compression facility we have two main -- two 10 11 main parts. We have a low compression compressor which is 11 12 electric drill and a high pressure which is turbine driven, and 12 13 really the main key thing here is we only have one gas 13 14 compression train, so we're going to be the only facility on 14 15 the Slope that's 100% dependent on one gas compression train. 15 16 CHAIRMAN JOHNSTON: what happens when that -- if that 16 17 train goes down? 17 18 MR. RICHARDS: we'll be shut down till it's fixed. If 18 19 the big compressor goes down, we won't be able to operate. 19 20 CHAIRMAN JOHNSTON: So you shut-in wells? 20 21 MR. RICHARDS: Yeah. One quick slide on production 21 22 allocation. We anticipate using actual sales volumes as the 22 23 basis for the well, but that would -- the number of horiwntal 23 24 wells and the development plan currently in place, actual 24 25 royalty allocation will be based on reservoir modeling. Using 25 AOGC . · · Page 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 munber of wells we're going to have on each pad in the 11 long-term we're requesting that a quarterly test as a minimllill 12 requirement thereafter. And we also do not have options that 13 Prudhoe Bay has in tenus 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 18 19 20 21 22 23 24 25 On freeze protection -- do you have any questions about these s !ides? · CHAIRMAN JOHNSTON: I was just curious in tenus of your well testing frequency. Has that proposal been ran by the royalty owners, have they agreed to that? MR. RICHARDS: I don't know. Mike, can you help me? No. I guess it has not been, no. CHAIRMAN JOHNSTON: okay. MR. IRELAND: The royalties will be allocated off the Metre Cewt It.eporting, Inc. . RE: Alpine Oil Pool Page 59 reservoir modeling, as Brian stated in kind of long-tenu reserve picture versus the short-tenu daily production (indiscernible). CHAIRMAN JOHNSTON: But the allocation process has all been agreed to? MR. IRELAND: The process, yes. The final decimals, tract allocations facing that work, no not yet. MR. RICHARDS: on the question on freeze protection that came up earlier. The injection wells will all have houses on them. The production wells are not going to have houses. Right now we're anticipating water break to be substantially in the future. We believe that producing wells don't neœ them. The first and primary method for freeze protection is going to be displacement with gas. We can also use diesel. To displace we'll have a small amount of methanol that we can also use, but since we can't supply -- resupply with methanol very conveniently in the winter we -- or after the actual is out, I mean we'll be trying to minimize the use of methanol. So gas displacement and diesel displacement would be the two primary means of freeze protection. CHAIRMAN JOHNSTON: so what about ensuring that your surface safety valve closes when you neœ it to close? I mean we've seen a nllillber of examples across the North Slope where these valves can freeze up if they are not wrapped somehow. Are you going to be wrapping these things in electric blankets Page 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 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 Page 57 - Page 60 . . . AOGC . CondenseIt 1M Page 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 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 together that they're relatively close to the buildings. So that instnullentation will be encl- -- in the buildings. CHAIRMAN JOHNSTON: That's what I was..... MR. RICHARDS: okay. CHAIRMAN JOHNSTON: NOW in tenus of the other question I had relative to the wisdom of taking out the subsurface safety valves on your marginal wells. Could you fully expand upon that what additional steps may be incorporated in the facilities to ensure that the -- if there was a failure that the oil would not -- there you go. MR. RICHARDS: A couple of things about the pads themselves. You can't see in this one anyway. But these pads are all with the current stonn water regulations, these pads are all drained into what we're calling sumps. But basically the pads -- historically the North Slope pads are graded flats or control flow in the direction. Ours are controlling flow into collection areas. So anything that gets onto the pad in a substantial volume would flow into one of these collection areas and we could contain it there and then remove it with vacuum trucks or pumps. So the pads themselves are drained to collection -- collection areas. Page 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 contaiument 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 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. IRELAND: I'd ask for a short, five minute recess before we continue? CHAIRMAN JOHNSTON: That would be fine. That will give us the opportunity to collect some additional questions. (Off record - 11:25 a.m.) (On record - 11:35 a.m.) CHAIRMAN JOHNSTON: Back on record. Mr. Ireland, I guess you're due to sUl1ll1larize. We also have a series of questions. Do you wish to do your sUl1ll1lary and then the questions or..... MR. IRELAND: That would be great, yes, if I could just go ahead and sUl1ll1larize first. Commissioners, I just mentioned that the reason we're here this early prior to field start-up, which is not until the MetN Cewt lteporting, Inc. . RE~ Alpine Oil Pool Page 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 infonnation 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 24 25 I'd just like to follow-up for a minute the intent in our request with the subsurface safety valves is to start with subsurface safety valves in all of our wells. The request for Page 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 SUl1ll1lary 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. Page 61 - Page 64 AOGC . CondenseIt TM Page 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 fïnd 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 9 Torok sands there has been -- I may be stating this wrong, but 10 in the Colville Delta area, I believe there's been an attempt 11 at a well test or two in the Torok interval in the older 12 Colville Delta wells. As I said before, it's oil bearing. 13 There's a few sequences of sandstones within the Torok. The 14 Torok is a thick sequence of prograding shales and clastics 15 from west to east, and most of the sands that we've seen in the 16 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 Page 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. I will be peripherally involved 13 with that work. 14 CHAIRMAN JOHNSTON: 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? · · MetD Cewt lteporting, Inc. . RE: Alpine Oil Pool Page 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. 9 CHAIRMAN JOHNSTON: In terms of the ability of these 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 Page 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 MR. CHESTER: That is correct. 15 CHAIRMAN JOHNSTON: why wouldn't you necessarily go to 16 the Class 1 to begin with? 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 CHAIRMAN JOHNSTON: so if the annular disposal doesn't 25 prove to be an option for you then you're pretty much going to Page 65 - Page 68 AOGC . . CondenseIt 1M Page 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. 11 CHAIRMAN JOHNSTON: okay. Does your estimate of 35 to 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? 15 MR. IRELAND: That represents the base development 16 plan. 17 18 19 20 21 22 23 24 25 · CHAIRMAN JOHNSTON: And..... MR. IRELAND: our publicly stated munber for Alpine reserves is 365 million barrels. CHAIRMAN JOHNSTON: And then what is the estimate of · the higher ultimate recovery for the new proposed plan? MR. IRELAND: I'd really prefer to wait to answer that question till we've had time to do the proper technical evaluation as well as economic evaluation. Obviously somewhat higher is what we'd be hoping. · Page 70 1 CHAIRMAN JOHNSTON: so sometime in the future you'd be 2 prepared to provide that estimate to the commission? 3 MR. IRELAND: Yes. 4 CHAIRMAN JOHNSTON: Any idea of how long that would 5 take? 6 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? MotN CMI't ltepørting, Inc. RE: Alpine Oil Pool Page 71 1 MR. IRELAND: Yeah. Probably the initial rates would 2 fall off to -- or (indiscernible - coughing) of each other is 3 it would fall off 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. 14 COMMISSIONER CHRISTENSON: I have one question. Do you 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 1'd suspect we need to keep the hearing record open. It's also 25 my understanding that the Department of Natural Resources Page 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 infonnation, as well as the DNR comments, 1'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, 1'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. 14 (Off record - 11:50 a.m.) 15 §@ QE rßQÇ§§DINº~ 16 17 18 19 20 21 22 23 24 25 Page 69 - Page 72 · · · AOOC . Cond.enseIt TM Page 73 1 CERTIFICATE UNITED STATES OF AMEIUCA 2 )ss. 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 STATE OF ALASKA I, Cary Wells, Notary Public in and for the State of Alaska. and Reporter for Metro Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Commission Hearing, was taken before Laura Fero on the 3rd day of December 1998, commencing at the hour of 9:00 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 3001 Porcupine Street, Anchorage, Alaska; That the hearing was transcribed by Laurel L. Earl to the best of her knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 8th day of December 1998. Notary Public in and for Alaska Metre Cetøt R.eporting, Inc. '. RE: Alpine Oil Pool Page 73 - Page 73 AOGC . CondenseIt 1M . =1#1 - apart =111 [1] 9:9 10:21 10:22 17:12 56 [1] 21:23 63:7 63:14 Alpine [76] 1:4 =112 [1] 13:25 42:21 48:3 56% [1] 6:12 active [1] 55:3 2:16 3:20 4:18 200 [2] 21:2 71:9 6 [4] actual [6] 23:8 4:19 4:23 5:2 00[2] 1:8 73:9 44:5 44:9 5:19 5:21 6:1 05 [1] 2:2 2000 [3] 17:24 63:1 47:25 63:8 42:17 44:21 57:22 6:3 6:4 7:7 57:24 59:17 · 1 [21] 6:2 6:3 64:16 600 [3] 20:21 21:2 7:18 7:22 7:23 6:5 6·':; 7:21 2000' [1] 18:7 71:9 add [2] 15:17 15:17 7:23 7:25 8:2 7:21 8:14 9:16 21 [1] 53:1 6000' [1] 66:3 adding [1] 28:12 8:4 8:15 8:17 12:12 13:25 14:9 22% [2] 6:12 6:14 6876 [1] 9:10 additional [12] 21:10 8:18 9:7 9:16 14:11 17:16 18:6 6976 [1] 9:10 25:13 28:22 29:25 9:17 9:18 9:20 24:25 34:1 63:4 2350' [2] 12:1 35:17 35:18 36:17 10:6 10:9 10:9 68:13 68:16 71:10 12:14 7 [8] 33:19 44:6 61:12 62:15 71:23 10:16 10:20 10:25 71:10 24 [11 49:1 44:11 48:9 50:15 72:2 72:4 11 :3 12:2 12:3 1-22 [2] 67:14 25 [3] 7:24 42:17 50:15 63:8 64:1 address [2] 50:11 12:7 13:17 17:10 35:22 700' [3] 12:18 14:18 17:12 18:4 18:7 62:16 I-A [1] 6:3 14:25 52:1 19:1 20:7 31:8 1-B [1] 6:3 25.080 [1] 36:5 addressed [1] 41:5 31:16 32:8 32:11 25.280 [1] 48:3 7000' [5] 26:4 adjacent [1] 55:1 34:12 35:6 36:4 1 0 [5] 42:20 42:21 26:14 47:20 47:22 42:22 43:16 63:6 25.540 [1] 2:24 47:24 adjust [1] 45:14 36:10 36:13 39:19 41:24 43:18 44:1 10,08Ø [2] 13:3 2500 [1] 47:11 75% [1] 8:25 administered [5] 44:7 44:12 47:9 70:20 2500' [1] 14:8 75' [1] 31:17 4:8 6:23 30:15 47:24 50:21 53:7 100 [2] 19:16 56:4 275-acre [2] 20:23 78% [1] 6:14 43:6 52:18 53:17 54:10 54:11 10ftJ [2] 16:18 21:19 79' [3] 15:9 15:10 administrative [2] 55:17 55:18 60:9 57:15 3 [8] 1:8 2:22 15:13 5:16 63:7 63:18 64:12 64:23 10ø0 [2] 9:4 10:25 6:3 6:5 9:23 8 [1] administratively [1] 65:5 65:16 69:18 29:3 63:5 71:10 63:8 34:21 alt [1] 21:2 1080' [4] 14:9 3-A [1] 800 [1] 12:10 affixed [1] 17:17 17:24 34:10 6:4 73:15 alternate [1] 44:17 11 [4] 7:5 62:16 30 [1] 10:14 82 [11 21:16 again [11] 9:11 alternately [1] 44:19 62:17 72:14 30' [1] 10:22 850' [1] 12:24 18:14 21:24 37:13 alternating [1] 22:3 1100' [2] 15:3 30-year [1] 20:11 8th [1] 73:15 46:2 50:13 51:1 always [3] 7:14 51:19 63:11 65:1 15:19 3000 [2] 26:12 47:9 9 [9] 1:8 2:2 60:25 72:9 29:3 29:21 33:20 67:2 12 [3] 43:15 53:4 3000' [3] 26:2 44:11 50:13 63:8 ago [1] 56:25 amenable [1] 28:20 67:24 26:17 44:9 73:9 agreed [3] AMERICA [1] 73:2 22:10 128ð [1] 57:9 3001 [2] 2:7 73:11 985' [1] 12:10 58:21 59:5 amongst [1] 16:25 · 13 [2] 37:6 65:21 3100[1] 47:14 1:8 2:2 ahead [4] 4:5 amount [5] 20:5 a.m [8] 13'JJ [1] 15:12 32 [1] 20:22 42:21 42:22 62:16 35:7 47:5 62:23 27:18 32:25 56:5 140-acl'e [3] 21:18 35 [5] 16:18 16:21 62:17 72:14 73:9 arr [3] 54:18 55:12 59:15 21:24 21:24 20:11 62:17 69:11 AAC [2] 2:24 48:3 55:13 Anadarko [1] 6:13 15 [2] 18:24 42:20 35' [1] 14:17 abandon [1] 45:10 airstrip [1] 54:3 analysis [1] 23:12 1580 [4] 18:7 21:25 35,000 [1] 41:14 abandonment [1] Alabama [2] 31:1 Anchorage [4] 1:7 48:17 52:5 3500' [1] 26:12 33:17 43:16 2:8 2:21 73:11 1506' [1] 26:18 365 [1] 69:19 ability [3] 20:6 Alaska [26] 1: 1 annual [2] 47:22 16 [3] 2:21 44:10 39 [1] 19:19 67:9 73:13 1:7 1:12 2:6 49:5 50:13 3rd [2] able [11] 26:6 27:6 2:8 2:16 3:16 annular [27] 7:19 16'JJ [1] 2:6 73:8 3:20 6:10 6:11 11:25 12:4 12:12 14:13 28:24 34:20 38:23 160-acl'e [2] 20:25 4 [9] 10:7 34:11 39:8 40:9 49:23 6:13 7:9 7:15 13:9 13:11 13:14 21:4 44:15 44:18 44:23 57:19 63:13 70:23 19:1 30:23 31:1 13:18 34:6 36:6 50:19 63:5 66:3 above [11] 10:6 31:5 43:17 53:4 36:7 36:9 40:5 17 [3] 30:24 31:4 70:19 53:4 73:3 73:5 40:9 40:10 40:12 53:2 40 [1] 54:22 12:7 12:21 14:4 73:7 73:10 73:11 40:15 40:18 41:2 18 [1] 20:24 14:14 14:15 16:10 73:17 41:7 41:24 42:1 40% [1] 69:12 19:20 50:21 64:23 1880' [1] 12:16 40' [1] 16:19 65:5 Alaskans [1] 72:10 42:7 66:23 66:25 19'1> [3] 14:17 19:15 400' [3] absolute [1] aligned [1] 26:3 68:7 68:24 14:14 14:19 70:18 annulus [2] 12:2 19:18 15:14 allocated [1] 58:25 access [1] 26:6 67:15 1977[2] 43:13 52:25 42 [1] 21:3 45:19 allocation [3] 57:22 1910 [1] 30:24 accesSIng [1] 57:25 59:4 answer [4] 30:3 45%[1] 20:11 accomplish [1] 26:8 64:20 69:9 69:22 1~[1] 6:1 48 [1] 18:25 according [1] 2:23 allocations [1] 59:7 answered [1] 42:3 1995 [11 6:2 5 [5] 10:18 18:25 accumulation [2] allow [9] 2:24 anticipate [3] 15:19 19% [1] 6:4 3:5 5:23 35:7 44:5 46:18 63:8 9:8 64:24 39:6 45:11 45:14 23:14 57:22 1991 [6] 1:8 2:6 5,000,000 [1] 48:18 achieve [2] 28:24 46:23 72:2 anticipated [1] 41:12 2:21 2:22 73:9 50 [4] 20:20 20:22 44:12 anticipating [2] 58:2 73:15 allowance [1] 48:15 · 42:22 72:14 acqUIre [1] 66:1 allowing [2] 5:15 59:11 2 [7] 6:5 9:7 54:15 63:4 68:9 50' [2] 17:12 34:12 acquired [1] 70:22 63:6 anyway [4] 38:13 69:1 71:10 500' [3] 12:19 12:21 acqumng [1] 28:18 almost [1] 44:25 51:2 61:16 68:13 2-A [1] 6:5 29:7 act [1] 64:2 along [3] 6:13 44:23 AOGCC [1] 48:7 20 [7] 2:24 10:14 5000 [2] 17:22 52:6 action [3] 5:16 54:12 apart [1] 54:2 Metre CMI1 :R.eporting, Inc. Index Page 1 AOGC . CondenseIt TM . APD - CHAIRMAN APD [1] 40:9 31:7 bearing [2] 65:12 breakup [1] 55:2 CDI-22 [1] 6:7 API [1] 19:19 associated [1] 38:15 65:16 Brian [8] 1:14 CD2- 35 [1] 6:8 appeM' [1] 70:9 assume [1] 6:20 become [1] 11:2 5:7 49:23 50:2 cement [8] 31:22 APPEARANCES [1] 18:17 22:10 23:21 begin [1] 27:3 27:4 50:23 51:1 52:1 33:13 41:8 41:18 · 1:9 43:1 52:13 66:21 27:8 31:14 31:16 59:1 45:10 45:11 46:15 appeariBg [1] 16:10 assuming [3] 26:19 64:12 68:16 brief[6] 3:15 5:25 50:20 applicaøt [1] 3:9 28:17 67:25 behind [1] 45:22 6:16 48:23 48:24 cemented [3] 31:21 application [5] attempt [3] 32:24 below [15] 9:5 55:19 41:16 45:12 2:15 4:25 34:15 35:12 64:6 65:10 10:7 10:25 12:2 briefly [5] 2:24 central [1] 20:17 48:3 attention [1] 37:9 12:14 12:16 13:5 13:24 44:2 50:11 certainly [10] 11:6 14:2 31:17 31:20 53:14 apply [4] 8:4 audience [3] 3:6 31:25 34:10 35:19 brine [1] 49:11 16:2 18:22 23:23 19:12 25:8 63:15 3:25 9:14 46:14 65:4 65:18 authoring [1] 44:14 50:18 bring [2] 27:14 63:14 70:6 70:20 71:17 appl'ØflCh [1] 35:13 2:18 appmpriate [1] authorities [1] 40:16 benefit [1] 9:12 brings [1] 37:8 certify [1] 73:6 18:19 benefits [1] 36:4 38:4 47:16 authorized [1] 13:19 22:24 briny [1] 13:6 CHAIRMAN [110] 64:10 69:9 70:13 automated [2] 48:9 Bergschrund [1] 6: 1 brittle [2] 16:1 1:10 2:3 4:1 6:5 8:14 9:9 16:5 4:5 4:10 4:13 appropriately [1] 48:10 9:16 12:12 64:22 6:19 6:22 6:25 42:4 automatic [3] 5:13 best [9] broadly [1] 46:6 7:3 7:10 7:13 19:22 20:18 approval [3] 21:12 49:3 64:1 24:14 34:23 46:21 broken [1] 20:16 8:7 8:13 8:21 23:4 48:7 automatically [1] 51:1 52:1 64:19 Brookean [2] 65:5 9:2 9:11 9:14 appmvals [1] 23:12 45:4 73:13 65:22 9:23 10:1 10:4 approve [1] 41:20 available [1] 26:24 better [3] 16:24 bubble [1] 19:20 10:8 10:17 11:4 appt'f)W4 [3] 4:22 average [8] 14:13 17:2 50:5 build [1] 55:14 11:9 11:15 11:20 11:24 12:25 13:8 22:25 23:3 17:12 19:13 19:16 between [1] 9:9 build-up [1] 47:1 13:13 13:19 13:22 appt'fMfiMMe [1] 64:6 19:17 47:9 47:17 17:17 21:2 22:1 build-ups [1] 47:3 14:21 15:5 15:9 71 :11 22:13 35:14 aq1Ùfer [1] 19:21 38:14 buildings [3] 60:20 15:11 15:14 15:21 AIlCO [12] 1:12 averaging [2] 10:14 beyond [2] 25:5 61:5 61:6 16:8 16:13 16:16 2:16 3:16 3:19 14:17 25:21 buildup [1] 16:22 17:3 17:7 47:11 6:11 6:14 7:5 avoid [1] 46:14 big [1] 57:19 built [1] 53:24 17:15 17:19 18:9 18:24 30:22 30:22 aware [1] 8:8 bigger [1] 11:8 18:12 18:17 18:20 31:4 53:2 away [3] 13:15 18:7 biggest [1] bump [2] 32:6 19:3 19:6 22:8 57:9 33:13 22:13 22:20 23:6 AIlCO's [1] 13:10 24:21 billion [1] 19:18 burn [1] 28:23 23:14 23:21 23:24 · AIlCOItW[I] 31:6 B [2] 37:20 40:10 bit [12] 11:1 11 :11 burned [1] 24:6 24:8 24:11 Arctic [1] 6:10 bachelor [1] 30:23 11:25 19:17 29:22 24:17 24:24 25:3 38:3 burning [1] area [52] 2: 19 4:20 bachelor's [4] 7:7 38:4 38:8 44:9 56:13 25:5 25:7 25:12 4:20 4:24 5:1 18:22 43:13 52:25 45:21 54:5 54:13 bu.siness [1] 53:1 25:15 25:18 27:2 5:17 6:1 8:16 background [4] 5:25 71 :11 C [10] 1:6 1:6 27:9 27:13 27:17 8:18 10:19 11:10 31:15 40:8 40:15 blank [1] 44:20 2:1 35:3 37:20 27:22 28:2 28:5 11:13 11 :21 12:7 backup [1] blanketly [1] 38:5 40:10 72:15 28:11 28:16 29:1 13:1 13:14 13:17 50:20 68:4 73:1 73:1 30:4 30:10 30:13 14:12 17: 1 20:17 Badami [1] 31:7 blankets [1] 59:25 CAMILLE [1] 1:11 30:17 30:20 31:9 20:19 20:20 20:22 badly [1] 4:16 blow-up [1] 53:25 Cammie [1] 31:12 32:1 36:11 21:1 21 :1 21:5 ban [1] blown [2] 54:5 2:10 36:19 36:23 37:1 34:3 21:16 21:17 21:20 bare [1] 54:13 camp [2] 54:4 55:7 37:11 38:3 39:6 24:23 24:23 26:4 69:12 Bluff [4] 12:9 cannot [1] 66:9 39:15 40:2 42:9 34:1 36:14 36:19 barrels [9] 19:18 12:21 42:12 42:19 42:23 12:22 34:9 cap [5] 19:20 41:14 37:5 46:13 50:6 41:14 47:9 48:18 Bob [1] 49:11 49:12 49:14 43:1 43:4 43:8 50:9 51 :13 54:5 52:6 69:19 70:16 2:10 capable [4] 43:11 43:19 43:22 62:9 63:15 65:10 70:18 70:20 BOP [4] 33:2 35:4 34:3 46:9 48:19 48:22 65:16 65:16 65:18 barrier [1] 12:8 35:9 38:22 40:17 48:19 64:8 48:24 49:7 49:15 67:17 67:25 70:16 12:17 12:19 14:15 BOPs [5] 31:24 capacity [2] 56:4 49:22 50:4 50:7 71:8 72:11 15:22 16:1 16:11 33:4 38:5 38:14 58:7 50:25 51:17 52:3 areas [8] 5:18 25:24 barriers [1] 10:23 39:16 Cary [1] 73:4 52:11 52:13 52:16 52:20 52:23 53:8 51:11 61:21 61:23 base [5] 9:19 21:8 bore [1] 33:3 case [9] 14:11 16:2 53:11 57:16 57:20 61:25 62:8 71:6 69:13 69:15 71:8 bottom [4] 22:14 18:8 20:5 20:12 58:19 58:24 59:4 arr-~. -.mt [1] 61:3 based [8] 9:18 32:9 39:9 39:10 21:14 21:16 22:2 59:21 60:8 60:15 32:1 au"att : [6] 14:5 9:20 13:4 20:2 bottomhole [4] 39:21 60 :18 60:22 61:7 14:18 14:23 15:1 23:8 57:25 69:13 46:18 46:21 47:19 cases [1] 17:13 61:9 62:1 62:14 15:6 50:21 70:8 boundaries [3] 8:8 casing [28] 12:1 62:18 64:17 65:2 artificial [2] 44 :15 baseline [1] 36:15 24:19 29:8 12:3 12:13 31:20 66:6 66:9 66:14 56:15 basic [1] 54:19 boundary [3] 31:25 32:11 33:12 66:23 67:2 67:4 ash [1] 8:1 33:14 33:19 33:20 67:7 67:9 67:20 · 12:20 basis [5] 47:22 49:6 8:7 55:21 33:20 34:16 34:21 68:6 68:12 68:15 aspect [1] 44:1 57:23 65:24 71:16 bracketed [1] 9:18 35:6 35:8 38:18 68:24 69:3 69:8 aslleMlHy [1] 39:21 batch [1] 32:20 break [4]42:19 52:8 38:20 38:20 38:24 69:11 69:17 69:20 assÏpø4 [1] 31:8 bay [1] 7:6 14:13 59:11 62:10 39:9 39:10 41:16 70:1 70:4 70:8 asSI:' -litS [2] 31:3 19:1 31:7 43:17 breaks [2] 3:13 44:11 44:11 50:14 70:15 70:22 71:5 55:9 58:13 39:18 50:15 67:22 67:25 71:13 71:22 MetN c..n Aeporting, Inc. Index Page 2 AOOC . CondenseIt 1M . challenges - datum challøøBs [1] 45:]6 collar [1] 32:1 completed [4] 22:22 consists [2] 2:8 coughing [1] 71:2 chaJlCe [1] 39:8 collars [1] 31:23 23:11 28:4 44:13 33:16 countIy [1] 54:9 ch-.e [2] 21:15 collect [1] 62:15 completing [2] 23:15 construction [2] 41: 1 couple [6] 27:19 38:10 collected [1] 58:1 32:23 41:7 38:9 53:15 56:25 · ch~s [6] 29:7 collection [4] 61:21 completion [9] 5:12 contact [3] 2:13 61:15 69:3 33:8 34:22 38:7 61:22 61:25 61:25 32:15 34:21 44:8 10:14 10:15 course [7] 3:1 42:6 46:15 44:17 45:9 47:16 contain [2] 8:19 20:10 23:17 25:15 chM_I [7) column [1) 17:8 50:12 63:6 61:23 47:8 71:4 71:11 8:1 53:19 53:21 54:14 Colville [27) 4:18 completions [4] 34:23 contained [3) 62:4 Court [2) 2:12 54:15 54:17 54:25 4:20 4:21 4:22 34:23 43:25 44:4 62:6 62:8 73:5 chuBeliæd [1] 65:19 4:23 5:1 7:22 components [1] 26:16 containment [2) 5 1:22 7:25 8:2 8:5 cover [4] 5:3 24:3 characterize [1] 11:9 8:16 8:18 8:24 compressed [1] 56:11 62:8 26:4 30:8 characteriæd [1] 8:25 11:18 11:18 compression [4] 57:10 contingencies [1] covered [3] 5:6 12:15 14:8 14:12 51:11 57:1 I 57:14 57:15 31:23 44:6 46:17 cheJDical [1] 52:25 53:18 53:18 55:22 compressor [2] 57 :11 contingency [3] 20:6 CPF-2 [2] 54:9 Chester [45] 65:10 65:12 65:16 57:19 68:6 68:21 55:25 1:14 65:18 65:21 comprised [1] continually [1] 5:6 30:8 30:9 combination [1) 44:23 12:4 35:9 create [2] 34:16 30:12 30:16 30:19 computer [1] 47:7 continue [4] 25:19 45:25 30:21 30:21 31:12 combining [1) 34:9 concentrate [2] 24:15 38:11 48:7 62:13 cretaceous [1] 7:19 31:14 32:3 33:11 coming [8) 13:24 24:16 continued [2] 26:15 criteria [4] 41:19 33:25 36:13 36:22 14:6 25:22 32:23 concern [4] 51:3 34:24 51:9 64:4 64:5 36:25 37:3 37:8 55:22 63:10 66:2 37:14 37:16 37:20 72:9 63:18 63:21 68:4 continuing [2] 21:9 critical [4] 35:8 37:22 37:25 38:2 commencing [1] 73:9 concerned [1] 10:23 32:6 38:23 63:3 63:9 38:19 39:8 39:14 concerns [1] 47:25 continuous [4] 11:8 crossing [1] 54:8 39:17 40:7 40:22 comment [1] 70:14 conclude [1] 12:10 17:1 39:4 crossover [1] 50:19 42:9 40:25 41:13 42:3 comments [21 72:1 concludes [3] contours [1] 47:24 cubic [4] 27:20 27:20 42:11 42:24 67:4 72:3 10:16 contribute [1] 30:2 50:22 70:11 48:18 56:3 67:6 67:8 67:13 commercial [2] 8:11 conditioning [1] contributions [1] curious [1] 58:19 67:23 68:9 68:]4 8:19 68:17 69:2 56:12 70:10 current [24] 20:1 chelre [1] comnnsslon [27] conditions [2] 38:25 control [1] 61:20 20:16 21:8 21:19 58:7 1: 1 2:7 2:20 Chriøte08Øl1 [17] 2:24 3:2 3:8 64:7 controlled [4] 44:14 22:9 22:15 22:25 19:6 23:22 30:5 conducted [3] 2:23 45:3 48:12 49:4 23:7 23:17 23:25 1:11 2:11 7:12 24:7 27:2 27:24 · 19:4 31:10 33:9 31:13 35:15 35:24 48:2 49:5 controlling [2] 6:12 28:6 28:10 31:23 33:24 42:14 43:21 36:7 38:6 39:2 conductive [3] 45:25 61:20 32:4 32:15 32:17 50:10 52:4 52:10 40:5 41:11 41:17 46:1 46:14 controls [2] 6:14 35:5 35:21 61:17 53:10 57:5 57:7 48:12 48:15 51:5 conductor [4] 31:17 60:14 66:17 69:6 71:14 71:20 51:10 53:11 66:14 35:19 44:10 50:13 conveniently [1] 70:2 73:8 73:10 curve [1]67:24 circle [1] 53:25 Commissioner [39] configuration [2] 59:17 curves [1] 20:9 civil[1] 43:13 2:9 2:9 2:10 44:22 45:15 convert [1] 20:7 cut [7] 10:19 10:24 clarify [1] 40:3 3:18 7:11 7:12 confining [7] 14:5 conveyed [1] 32:18 16:20 17:7 17:10 Claøs [9] 13:25 34:1 19:4 19:5 31:10 14:19 15:2 15:4 cooling [1] 56:17 17:14 44:20 44:2 46:19 50:11 31:11 33:9 33:24 15:23 16:6 50:21 coordinated [1] 48:14 cut-off [1] 20:22 68:9 68:13 68:16 37:12 37:15 37:17 confused [1] 37:17 core [16] 20: 17 20:19 cutting [1] 34:6 69:1 37:21 37:23 38:1 connects [1] 54:11 20:20 20:22 21:5 cuttings [3] 68:10 clau-ic [2] 15:2 39:12 40:3 40:19 conservation [5] 21:16 21:17 21:20 68:18 68:23 16:4 40:23 41:10 42:2 1:1 2:7 5:23 21:25 22:5 22:7 claøtics [1] 65:14 42:5 42:13 42:14 73:7 73:10 24:22 24:23 65:8 cycle [3] 38:10 38:11 42:16 43:20 43:21 38:16 clellllt [2] 39:9 55:10 50:10 52:4 52:10 conserving [1] 5:21 70:16 71:8 cycles [1] 26:25 clear [1] 68:22 53:9 53:10 57:5 consider [18] 2:15 Corporation [2] 6: 11 D [10] 1:6 1:13 Clearly [1] 57:7 71:14 71:20 2:17 2:25 3:3 6:14 51:5 2:1 35:11 35:12 cloøe [14] 29:19 comnnsslOners [3] 3:9 4:10 6:25 correct [11] 10:7 36:12 37:18 37:22 32:12 35:]3 36:14 1:10 3:25 62:24 7:14 14:15 19:6 13:21 17:21 22:12 72:15 72:15 59:22 60:12 60:23 common [3] 9:8 28:10 30:17 31:13 28:1 32:3 36:22 daily [2] 2:21 43:22 48:24 52:20 39:14 62:11 68:14 59:2 60:24 61:4 61:5 44:17 45:19 53:11 64:3 69:2 data [20] 21: 10 28:3 63:21 72:5 72:8 compact [4] 56:22 consideration [1] correctly [1] 33:25 36:12 40:9 72:12 22:9 56:22 56:23 57:3 51:12 correlatable [1] 12:7 40:11 40:15 40:17 doøe« [1] 49:3 compare [11 71:5 40:20 41:3 41:25 cloøely [3] 63:21 compartmentalization considered [7] 2:25 correlating [1] 9:8 58:1 65:8 65:22 4:3 18:1 8 30:18 66:2 66:3 [1] 11:5 38:8 43:9 52:21 correlation [1] 38:14 65:25 66:5 67:13 cloøer [1] 29:7 competence [1] 4 1:25 considering [1] correlative [1] 5:23 68:3 68:5 71:23 · cloøes [1] 38:7 corresponding [1] date [10] 2:5 8:9 59:22 competent [6] 15:25 consist [3] 44:8 8:12 8:20 10:15 clOIIe8t [1] 20:18 16:2 33:21 34:18 49:8 44:19 49:11 13:9 19:21 65:18 coal [1] 12:22 40:12 41:6 consistency [1] 4:25 corresponds [1] 47:22 65:20 66:18 COMt [1] 43:15 complete [4] 35:18 consistent [2] 16:25 costs [3] 26:1 26:5 datum [2] 47:18 coil [2] 45:13 48:5 37:2 37:6 65:22 32:4 39:10 47:22 M8tN c..t lteperting, Inc. Index Page 3 AOGC . CondenseIt TM . Dave - evidence Dave [1] 2:9 develop [5] 20:19 disposal [33] 2:18 70:11 43:14 Davi4 [2] 1:10 25:25 28:2 36:23 7:19 7:20 12:1 drinking [1] 13:6 engineering [3] 18:23 50:6 45:16 12:4 12:8 12:12 drive [2] 2:8 26:3 43:13 52:25 days [4] 35:6 38:22 developed [1] 20:20 13:9 13:11 13:14 drived [1] enhance [1] 46:2 13:18 13:24 13:25 56:11 · 39:18 58:14 developing [1] 36:20 14:7 14:10 16:23 driven [1] 57:12 enhanced [2] 29:24 deals [1] 48:9 development [47] 17:15 17:20 36:4 drop [1] 62:9 48:2 Dec0Mher [4] 1:8 3:19 5:19 6:6 40:6 42:7 50:12 enlarge [1] 46:12 dryhole [1] 33:15 2:5 73:9 73:15 19:10 20:16 21:8 55:11 56:9 56:18 enrichment [1] 26:21 deci.4 [1] 38:9 21:13 21:16 22:9 66:24 66:25 67:17 drying [1] 56:12 22:11 22:15 22:16 68:8 68:11 68:22 Ds [1] 38:2 ensure [3] 51:21 deciMals [1] 59:6 23:2 23:7 23:17 68:24 69:1 due [3] 51:23 61:13 22:17 32:19 decisioo. [2] 3:2 23:20 23:25 24:2 dissolved [1] 13:2 62:19 ensunng [1] 59:21 23:8 24:3 24:5 25:11 entire [3] divided [1] 14:18 duration [1] 65:3 17:8 decisioBS [1] 28:15 25:20 26:1 26:17 22:7 36:24 decli1le [1] 47:10 27:2 27:24 28:6 dividing [1] 15:1 during [4] 20:10 entirely [2] 8:5 28:10 29:3 44:10 DNR [1] 72:3 26:22 26:25 55:14 decrease [1] 17:10 45:9 45 :14 46:24 8:9 doesn't [4] E [10] 1:6 1:6 decticMie4 [1] 69:1 54:22 56:24 57:24 38:17 environment [5] 5:21 55:3 68:24 70:9 2:1 2:1 9:19 51:2 51:5 51:7 deeper [2] 11: 1 63:2 63 :13 63:16 72:15 72:15 72:15 50:14 63:20 66:2 69:5 dog [1] 49:20 73:1 73:1 63:22 def.1I11t [1] 44:8 69:12 69:13 69:14 done [8] 13:3 13:18 eager [1] 64:12 environmental [1] 69:15 72:10 13:20 33:3 40:25 31:3 defer [2] 50:2 52:1 developments [1] 40:25 41:15 66:11 Earl [1] 73:12 environmentally [1] defiøe [3] 2:16 20:2 dotted [1] 55:21 early [1] 62:25 51:12 20:22 48:]7 deviate [1] 46:5 Doug [13] 1:13 east [4] 18:5 53:19 envision [3] 45:8 defi_4 [2] 9:7 diagram [7] 8:1 5:4 5:6 6:17 54:17 65:15 45:12 46:22 9:21 9:5 9:15 9:17 30:8 37:12 40:3 east-west [1] 11:14 EOR [1] 22:3 defiMtely [1] 62:7 12:11 12:23 14:6 42:24 64:25 67:1 eastern [1] 54:2 EPA [1] 33:25 defilÙtioll [2] 5:11 diameter [1] 44:9 67:2 67:3 67:4 econolDlc [3] 23:12 equal [1] 17:22 63:5 diesel [7] Douglas [2] 1:14 26:7 69:24 depue [6] 32:14 30:21 equipment [11] 5:14 7:7 49:11 49:11 49:14 econolDlcs [4] 20:3 48:9 49:9 55:9 7:8 18:23 30:23 59:14 59:19 67 :15 down [22] 10:6 21:11 23:17 24:21 55:10 56:18 56:24 43:13 52:25 difference [5] 22:13 10:13 10:24 12:2 effect [1] 39:7 57:4 64:1 64:4 depwIes [1] 11:22 22:14 33:19 44:22 12:3 12:24 13:5 effective [2] 64:8 deF -:::.t~o¡¡ [1] 14:1 14:25 17:1 15:12 · 6:4 56:20 26:11 33:5 39:18 64:14 Erwin [25] 1:13 Delta [9] 8:16 8:18 different [11] 4:17 52:5 53:22 53:23 effectively [2] 6:14 5:6 42:24 42:25 14:8 14:12 51:11 14:12 19:23 32:23 57:17 57:18 57:19 45:23 43:3 43:7 43:10 51:24 53:18 65:10 37:24 41:22 45:2 66:2 66:16 71:9 effects [1] 49:16 43:12 43:23 43:24 65:12 51:8 58:13 58:14 downhole [1] 58:1 efficient [1] 46:11 48:21 48:23 d.eBte__Mied [1] 60:9 64:14 49:1 49:10 49:21 36:9 dip [2] 11:20 11:22 downside [1] 20:12 efforts [1] 47:2 49:23 50:2 50:5 Der -Bt [2] 69:4 direct [2] 38:14 drained [21 61:18 eight [31 53:4 53:23 50:8 50:11 51:16 71:25 47:2 61:24 55:13 51:25 52:7 62:11 depeH[l] 46:11 direction [5] 11:14 draw [1] 18:5 eighth [1] 5:14 especially [2] 29:12 drawn [1] 72:11 de,lU hAt [1] 57:15 26:10 26:12 26:12 55:20 either [3] 39:24 61:20 dril1[29] 13:25 14:1 49:14 56:21 essentially [10] 32:3 de'rluf: [1] 44:20 directional [2] 20:18 24:4 24:8 electric [2] 33:13 33:15 33:17 35:13 57:12 depiet [1] 44:7 46:15 24:21 25:2 25:10 59:25 35:14 36:6 41:6 d.epletioo [1] 21:15 direction ally [1] 25:13 26:3 32:8 electrical [1] 44:18 44:22 67:18 d.epdIs [1] 32:10 32:13 32:17 35:18 establish [2] 2:16 9:10 44:11 electricity [1] 55:16 32:20 34:19 35:12 11:11 derive4 [1] 11:12 directly [4] 2:14 35:22 35:23 38:20 elongate [1] 11:14 established [1] 24:22 deøcrihe [4] 15:21 37:5 55:7 63:20 39:19 39:21 40:19 elsewhere [1] 60:9 estimate [4] 15:22 ]6:6 51:2 discovered [2] 6:1 45:11 45:17 54:15 69:11 deSCtWM [3] 44:10 8:21 54:21 57:12 69:1 Elsmarian [1] 11:12 69:20 70:2 70:15 51:18 54:1 discretion [2] 48:15 drilled [8] 6:2 emerging [1] 45:21 estimates [1] 69:5 descriptien [2] 35:13 51:18 6:7 21:3 21:17 employed [1] 43:14 evaluate [1] 66:21 55:19 discuss [5] 5:5 22:18 44:12 45:13 employing [1] 31:16 evaluated [1] 25:22 deøerye [1] 51:13 5:5 7:18 43:24 46:20 enable [3] 33:4 evaluating [4] 19:22 de... [2] 32:7 50:24 drilling [32] 5:5 34:19 35:16 28:19 65:24 66:10 34:21 discussed [2] 34:8 5:11 5:25 6:4 encl [1] 61:6 evaluation [2] 69:24 desUe [1] 38:24 39:1 23:8 24:16 26:15 enclosed [1] 49:22 69:24 detail [1] discussing [1] 18:15 26:]7 29:6 30:8 enclosure [1] event [1] 68:7 38:8 30:22 31:2 31:6 42:15 · ~[1] 38:25 discussion [3] 10:16 31:15 31:25 32:14 encounter [1] 45:24 everybody [2] 2:4 detU'......:t:...itm [3] 34:2 41:5 32:22 34:12 34:15 encourage [1] 3:10 53:14 3:2 3:]2 34:2 displace [1] 59:14 34:24 35:1 35:5 end [2] 5:4 5:8 everybody's [1] 51:11 detenltiøe [2] 34:18 displaced [1] 67:15 35:20 38:17 39:25 Endicott [1] everywhere [1] 66:5 46:22 48:6 63:1 31:7 41:25 displacement [3] 63:6 64:12 66:18 engmeer [2] 3:22 evidence [2] 8:9 59:14 59:19 59:19 66:17 MetN c...t Reporting, Inc. Index Page 4 AOGC . CondenseIt I'M . exactly - happy ex~ [2] 40:4 fail [1] 49:3 64:22 49:10 49:12 49:16 geology [11] 5:4 54:13 fails [1] 45:3 fit [3] 38:17 41:17 49:17 49:19 58:17 6:18 7:8 7:9 exatllple[1] 18:9 failsafe [1] 45:3 50:5 59:8 59:13 59:20 7:19 7:20 7:20 ex- ,les [3] 45:18 failure [3] five [111 2:5 6:2 59:24 12:1 40:21 41:4 51:21 freeze-protected [1] 67:6 · 45:18 59:23 61:13 62:2 24:5 24:10 31:5 exceetl [21 34:14 Fairbanks [1] 31:5 32:22 56:21 67:14 geometry [1] 29:5 7:9 62:12 63:7 64:13 freezes [1] 60:12 germane [1] 3:8 49:1 fairly [1] 15:15 excellent [1] 10:24 fixed [1] 57:18 freezing [2] 60:6 get-go [1] 27:9 exception [1] fall [5] 8:5 8:9 Fjord [2] 6:3 14:11 60:17 giving [3] 20:13 45:1 8:12 71:2 71:3 excitø4 [1] 64:12 far [4] flash [1] 9:24 frequency [3] 48:14 20:14 20:23 8:8 29:13 flats [1] 61:19 58:20 72:2 glauconitic [1] 9:22 excuøe [71 15:11 36:17 41:14 30:22 36:13 40:16 farther [1] flexibility [3] 63:1 front [3] 3:8 45:22 goes [8] 15:16 22:4 24:21 63:11 53:19 53:21 54:8 45:18 49:23 67:16 64:2 64:3 exelllptiøn [5] fault [6] 17:19 17:23 flood [7] 26:22 fronts [1] 52:8 54:18 57:17 57:19 5:15 17:24 18:6 18:10 26:25 frost[2] 31:18 29:4 29:9 29:19 46:1 27:25 28:2 28:6 31:19 gone [1] 13:15 29:21 faulting [2] 14:9 28:9 29:16 fuel [4] 27:6 28:23 good [8] 2:3 30:9 exhihit [4] 9:23 45:20 flooding [1] 19:24 29:22 56:12 30:10 37:11 51:25 10:7 10:18 17:4 faults [IS] flow [16] 10:23 33:5 fulfilled [1] 35:21 52:12 65:4 65:22 10:12 GOR [4] 29:3 existittg [3] 29:19 10:13 10:19 10:23 45:4 45:25 48:20 full [5] 35:24 47:10 29:9 46:6 54:9 11:4 11:8 17:3 51:20 53:20 55:3 58:7 66:1 66:21 29:10 29:21 exists [1] 65:19 17:7 17:9 17:13 55:3 58:13 60:3 fully [3] 61:11 62:3 grade [1] 56:9 exits [1] 44:21 18:1 18:1 44:20 61:20 61:20 61:22 62:6 graded[l) 61:19 exp8aCi [3] 45:25 46:14 62:3 64:5 function [1] 47:2 gradient [1] 67:24 26:22 45:23 61 :11 favor [1] 16:5 flowing [1] 64:9 funded [1] 22:25 graduate [1] 7:15 ex'.... [1] 25:10 favorable [1] 23:18 flows [1] 55:2 future [5] 19:11 graduated [2] 43:12 expeet [8] 24:14 feature [1] 38:15 fluid [1] 16:9 32:14 34:18 59:12 64:2 52:24 49:1 52:4 52:7 February [1] 13:24 57:1 67:17 68:1 70:1 grain [1] 9:21 68:8 68:22 53:16 56:10 62:9 feet [11] 9:4 10:14 fluids [6] G[3] 1:6 2:1 grant [1] 40:15 13:15 68:1 10:21 10:25 21:3 72:15 granted [4] 34:21 34:7 56:6 67:10 expødetl [1] 20:4 27:20 27:20 48:18 67:21 68:19 gain [2] 23:4 26:20 35:1 39:13 40:13 exJM'dÌIII [1] 70:21 56:3 71:9 71:10 flushed [1] gammg [1] 23:12 gravel [4] 34:4 67:15 eXpeMive [1] 24:20 Fero [2] 2:12 73:8 focus [1]47:2 gamma [2] 9:18 34:5 34:5 55:15 · 13:8 few [2] 10:17 65:13 9:20 gravity [1] 28:21 expen01lee [4] follow-up [1] 63:23 30:25 31:1 43:15 field [52] 3:20 4:15 gas [44] 1 :1 2:7 great [2] 30:7 62:22 expel'Íe1lGes [1] 31:2 5:1 5:1 5:10 followed [1] 23:11 9:8 19:20 19:24 6:1 6:9 7:21 following [2] 29:2 20:1 20:7 20:14 greater [1] 8:25 expert [14] 2:25 13:4 15:12 16:21 3:1 3:3 4:3 7:22 10:15 11:6 48:1 21:6 22:3 22:5 22:24 22:24 25:9 7:1 7:14 18:18 11:7 19:23 20:4 foot [2] 20:21 22:1 22:6 26:23 26:25 grinding [1] 20:17 20:19 21:4 27:6 27:10 27:11 34:3 19:7 30:18 31:13 21:10 21:11 21:14 footprint [1] 32:25 27:14 28:21 28:23 gross [5] 14:14 15:14 43:9 43:22 52:21 21:25 22:4 22:5 forced [1] 68:9 28:25 29:21 29:22 16:16 16:19 16:21 53:12 22:7 22:19 24:4 forecasts [1] 71:17 30:22 44:14 45:1 ground [2] eXpMati0D [2] 15:2 53:2 24:15 24:19 25:23 foregoing [1] 73:7 48:18 56:1 56:5 38:24 66:12 26:1 26:22 26:23 56:11 56:12 56:13 explele [1) 14:21 27:11 28:20 28:22 formation [9] 12:5 56:14 56:15 57:10 group [2] 32:22 12:9 12:14 12:17 72:10 expeft [1] 54:8 35:10 37:9 45:9 12:21 26:10 32:12 57:13 57:15 58:8 growth [I) 45:17 46:3 46:24 59:14 59:18 71:15 14:25 exp8l'tetl[1] 56:5 47:19 47:23 53:24 34:13 44:13 72:10 73:7 73:10 guarantee [1] 62:5 exports [1) 55:24 54:11 54:12 55:22 forming [1] 4:23 gas-oil [1] 10:15 guess [21] 3:15 ex.... [1] 46:22 55:23 56:1 62:25 forward [2] 63:14 gas-oil-ratio [1] 5:15 4:4 13:19 25:16 ex..... [1] 15:20 63:4 69:10 64:15 28:8 36:20 38:3 ex"'- [1] fields [4] 19:2 found [4] 8:19 gather [2] 21:10 40:4 41:21 49:15 66:12 65:25 exte1tt [1] 16:7 19:14 47:15 60:25 9:9 10:15 19:21 gathered [3] 51:18 51:19 55:6 fifth [1] 5:12 four [2] 39:18 56:21 3:25 58:23 62:19 63:4 exbi,3kting[l] filing [1] four-day [1] 8:9 65:8 64:11 64:18 66:24 47:3 23:2 39:23 general [2] 2:19 67:23 69:12 F[4] 1:6 40:4 final [1] 59:6 fourth [1] 5:11 36:14 Gulf [3] 31:1 43:15 72:15 73:1 fine [31 9:21 50:4 frac [1] 67:11 generally [8] 9:3 53:3 fah [1] 56:25 62:14 fracture [5] 14:25 10:12 10:13 10:22 guys [2] 42:14 65:2 faciJi+iet¡ [6] 5:7 finish [1] 64:11 15:20 34:16 67:12 11:18 13:5 19:16 half [6] 8:2 17:22 50:24 53:23 54:10 finished [1] 42:23 67:21 65:17 46:20 54:16 56:3 56:19 61:13 finn[l] 51:9 fractures [4] 15:6 generated [1] 20:10 71:3 · facility [3] 52:1 firmly [1] 24:22 16:1 16:14 16:14 generation [1] 55:16 hand [6] 4:7 6:22 57:10 57:14 first [IS] 4:14 5:10 fracturing [1] 16:5 gentle [1] 11:22 30:13 43:4 52:16 facilll [1] 59:7 6:6 14:6 24:13 frame [1] 24:1 geographical [2] 73:14 fact [3] 18:2 39:3 25:23 25:24 35:22 free [1] 48:4 4:20 5:1 hanger [1] 44:23 51:14 47:8 54:21 58:2 freeze [11] 49:7 geologist [1] 7:6 happy [4] 15:3 59:13 60:5 62:23 MetN CMft Rcporting, Inc. Index Page 5 AOGC . CondenseIt'I'M . hard - kicks 30:3 64:16 69:10 houses [3] 49:20 inefficiencies [1] interbedded [2] 12:6 4:13 6:19 6:22 hard [2] 27:25 60:3 59:9 59:10 39:11 12:20 6:25 7:3 7:10 has_ch1] 8:10 human [1] 5:20 infill [2] 26:15 26:17 interbeds [1] 12:22 7:13 8:7 8:13 hatcherecl [2] 8:3 hundred [2] 10:21 information [8] 29:4 interest [6] 6:11 8:21 9:2 9:11 · 8:12 27:19 29:11 34:24 35:16 6:15 22:10 23:1 9:14 9:23 10:1 head [IJ 2:8 hydrocarbon [1] 65:4 41:23 55:17 63:14 23:4 72:12 10:4 10:8 10:17 72:3 11:4 11:9 11:15 healih [2] 5:20 hydrocarboning [1] interested [3] 66:15 11:20 11:24 12:25 63:19 64:24 infrastructure [2] 66:19 72:10 13:8 13:13 13:19 hear [2] 2:17 49:24 hydrocarbons [1] 54:20 55:5 interesting [2] 60:8 13:22 14:21 15:5 heanh1] 38:16 8:20 initial [12] 19:17 66:20 15:9 15:11 15:14 hydrogeology [1] 19:19 24:15 24:16 intennediate [6] 32:7 15:21 16:8 16:13 hean. [7] 1:2 15:3 46:18 46:21 46:23 32:11 33:18 35:5 16:16 16:22 17:3 2:20 2:23 71:24 46:24 48:3 58:4 38:19 38:21 17:7 17:15 17:19 72:4 73:8 73:12 t.e [1] 50:18 71:1 71:3 18:9 18:12 18:17 heart [IJ 47:23 ice [1] 55:14 initiate [1 J interval [16] 8:17 18:20 19:3 19:6 22:2 9:9 12:4 12:6 heat [2] 50:17 61:2 Idaho [1] 7:8 inject [2] 21:5 12:7 12:8 15:8 22:8 22:13 22:20 beatï.g [1] 56:17 idea [1] 70:4 34:6 17:10 37:3 39:23 23:6 23:14 23:21 23:24 24:6 24:8 held [1] 65:25 identify [1] 3:16 injectant [2] 28:17 45:5 50:20 65:7 24:11 24:17 24:24 Hello [1] 18:14 ignored [1] 66:9 28:20 65:11 67:17 68:1 25:3 25:5 25:7 help [2] 58:22 67:5 II [6] 24:9 24:12 injecting [1] 16:8 interval's [1] 15:9 25:12 25:15 25:18 heJd)y [1] 73:5 25:3 44:2 46:19 injection [60] 2:18 intervals [2] 36:4 27:2 27:9 27:13 50:11 2:21 7:20 13:24 48:11 27:17 27:22 28:2 hereto [1] 73:14 immediate [1] 13:14 14:1 14:2 14:3 interwell [1] 26:18 28:5 28:11 28:16 hesiœøcy [2] 42:5 immediately [2] 17:5 14:10 14:11 14:16 introduction [5] 3:15 29:1 30:4 30:10 42:8 54:6 15:23 17:16 19:24 3:17 3:21 5:3 30:13 30:17 30:20 hi.. [8] 8:24 11:18 impact [1] 19:25 22:3 26:19 6:16 31:9 31:12 32:1 11:19 19:14 19:19 27:18 26:24 27:1 27:3 involved [6] 36:11 36:19 36:23 28:21 29:15 57:12 impacting [1] 46:7 27:8 28:24 29:24 4:15 37:1 37:11 38:3 hiper [4] import [4] 20:1 34:6 34:8 34:17 23:5 42:6 43:18 39:6 39:15 40:2 22:17 36:6 36:8 36:9 63:20 66:12 42:9 42:12 42:19 22:20 69:21 69:25 27:6 54:7 55:23 hiøJlest [2] importance [1] 51:6 36:9 40:9 40:10 Iowa [1] 52:24 42:23 43:1 43:4 20:15 40:13 40:16 40:18 Ireland [64] 1:12 43:8 43:11 43:19 51:13 important [1] 64:13 41:2 41:7 41:20 3:18 3:19 4:4 43:22 46:9 48:19 hiplY[I] 12:6 Improve [1] 29:18 41:24 42:1 44:1 4:9 4:12 4:14 48:22 48:24 49:7 · historically [1] 61:19 improved [1] 63:13 44:2 44:6 44:25 18:14 18:14 18:19 49:15 49:22 50:4 histery [1] 5:25 in-field [1] 70:] 1 45:23 45:24 46:13 18:22 19:7 19:8 50:7 50:25 51:17 46:19 47:4 49:3 22:12 22:16 22:22 52:3 52:11 52:13 hittitw [2] 12:18 Inc. [1] 1:12 49:4 49:13 49:14 23:10 23:16 23:23 52:16 52:20 52:23 14:19 incapable [1] 64:5 50:12 50:18 59:9 24:3 24:7 24:10 53:8 53:11 57:16 hole [16] 32: 14 34:22 inch [3] 17:22 17:23 63:15 67:16 68:1 24:13 24:18 25:1 57:20 58:19 58:24 36:1 36:17 37:4 17:23 68:10 70:11 25:4 25:6 25:9 59:4 59:21 60:8 38:22 38:24 38:25 include [4] 31:2 injectivity [3] 20:5 25:14 25:17 25:19 60:15 60:18 60:22 39:9 39:21 44:8 35:12 45:19 48:6 20:6 20:12 27:4 27:11 27:15 61:7 61:9 62:1 44:18 45:5 45:9 included [2] injector [2] 27:19 28:1 28:4 62:14 62:18 64:17 45:11 46:13 42:16 29:17 28:8 28:14 28:19 65:2 66:6 66:9 hoJe/iøwJlllediate [1] 42:18 45:20 29:2 30:4 30:7 66:14 66:23 67:2 36:1 including [1] 6:2 injectors [2] 22:1 54:23 58:25 59:6 67:4 67:7 67:9 holes [1] 32:22 incorporated [5] 45:6 62:12 62:18 62:22 67:20 68:6 68:12 hope [4] 22:2 3:20 4:17 6:12 inlet [1] 57:1 64:25 67:1 67:3 68:15 68:24 69:3 23:16 30:23 61:12 inordinately [1] 47:1 69:7 69:10 69:15 69:8 69:11 69:17 35:10 70:7 69:20 70:1 70:4 Increase [2] 21:14 install [1] 69:18 69:22 70:3 hopefal [2] 21:12 33:14 70:6 70:13 70:17 70:8 70:15 70:22 29:2 45:23 installed [5] 31:24 71:1 71:8 71:17 71:5 71:13 71:22 hopef\tHy [5] 4:16 increased [1] 22:17 48:10 48:13 49:4 isolate [1] 29:15 jump [1] 47:5 23:19 36:8 40 :14 Increases [1] 52:9 51:8 isolation [1] juncture [1] 38:9 63:12 independent [1] 28:15 instance [1] 46:13 50:19 instrumentation [4] itself [8] 28:20 55:19 Iurassic [3] 8:15 hopÏll& [2] 69:25 indicated [1] 68:7 57:8 60:16 60:21 14:19 15:20 70:17 indicates [1] 68:5 60:19 60:21 61:4 60:22 60:24 64:6 K[2] 1:14 30:21 61:6 hori3ØBS [1] 36:17 indiscernible [7] Ivishak [12] 8:22 keep[4] 31:19 68:22 horiaeMa1 [22] 20:23 33:10 37:7 40:23 insufficient [1] 20:5 8:23 9:2 14:2 71:24 72:3 20:24 21:17 21:19 42:17 59:3 65:6 insulated [1] 31:18 14:3 14:11 15:8 keeping [1] 38:13 21:21 21:24 26:1 71:2 insulation [1] 61:1 15:9 15:24 16:9 26:2 26:4 29:6 individual [2] 58:] integral [1] 45:8 17:2 68:17 Kenai [1] 56:25 29:12 32:9 32:11 72:7 integrity [2] job [4] 41:8 41:18 key [6] 26:16 54:10 32:12 32:13 32:20 32:12 57:13 63:2 63:5 · 33:3 44:8 44:12 individuals [1] 64:19 34:13 45:10 56:8 63:18 47:1 57:23 63:2 industrial [1] 13:25 intent [3] 23:22 jobs [3] 31:22 31:22 KH[I] 24:20 industry [3] 63:23 64:7 53:5 hot [1] 42:24 23:17 kick-off [2] 39:21 how [1] 73:9 30:25 43:14 intention [1] 60:2 Iohnston [172] 1:10 45:11 hO\ml [1]49:1 inter-well [1] 22:1 2:3 2:9 3:18 kicks [2] 26:10 4:1 4:5 4:10 26:11 MdN Cewt Reporting, Inc. Index Page 6 AOGC . CondenseIt I'M . kill - names kill [1] 49:] ] left [4] 7:25 9:]7 logs [10] 9:]9 12:12 10:5 10:6 10:7 million [4] 13:3 kilMi [12] ] 0:22 11:11 33:16 37:21 35:24 35:25 37:2 10:24 56:3 56:4 69:19 11:20 16:4 32:25 length [3] 26:25 37:6 37:10 65:23 master [1] 33:16 millions [1] 27:20 39:17 41:16 59:1 44:21 47:2 66:1 66:21 master's [2] 7:8 mind [1] 37:12 · 66:4 66:16 68:3 less [8] 16:5 17:13 long-term [2] 58:11 18:23 minimize [1] 59:18 71:10 19:16 19:17 48:17 59:1 material [2] 32:21 minimum [6] 14:24 Ki.... [6] 9:19 67:18 67:21 68:2 Longer [1] 26:1 33:1 29:6 31:17 46:8 10:12 14:4 14:18 lesser [1] 16:7 look [4] 3:11 20:9 materials [1] 55:9 46:24 58:11 15:18 16:7 letting [1] 41:11 21:10 26:15 minus [1] matter [8] 3:3 29:22 K.nock: [54] 1:13 level [6] 12:4 17:11 looked [2] 17:25 7:14 18:1 31:13 minute [2] 5:4 6:17 6:21 62:12 17:12 18:5 18:7 19:23 51:8 51:15 72:6 6:24 7:2 7:5 63:23 7:13 7:17 8:11 26:21 looking [1] 13:4 72:12 minutes [2] 42:20 8:14 8:23 9:4 lie [1] 65:7 ]7:24 21:16 25:21 matters [1] 53:12 53:16 9:13 9:15 9:25 life [1] 24:3 28:8 49:12 64:14 maximum [1] 5:24 miscibility [1] looks [2] 41:18 28:25 10:3 10:5 10:9 lifetime [1] 20:11 71:23 may [28] 3:9 15:5 miscible [12] 19:25 10:20 11 :6 11:12 lift [5] 44:15 44:15 lose [2] 38:25 68:21 15:17 16:4 16:19 22:2 22:19 26:19 11:17 11:22 11:25 45:1 56:15 56:15 Louisiana [3] 30:25 18:9 21:12 26:6 26:20 27:25 28:2 13:2 13:10 13:17 light [1] 28:21 43:12 53:3 28:2 28:5 28:5 28:6 28:9 28:16 13:21 13:23 14:24 low [4] 15:15 57:11 29:13 29:15 29:17 28:19 70:11 15:7 15:10 15:12 likely [3] 45:12 65:17 65:17 30:6 32:21 34:25 miss [1] 37:20 15:15 15:25 16:12 45:13 47:3 45:19 47:10 48:2 16:14 16:18 16:24 limestone [4] 14:15 lower [11] 12:17 51:1 51:20 60:8 model [1] 47:7 17:6 17:9 17:18 16:3 16:4 16:15 12:20 14:2 14:11 61:12 65:9 66:6 modeling [3] 57:25 17:21 18:11 18:13 Limestones [1] 14:13 15:23 18:25 70:11 72:5 59:1 68:17 37:6 37:8 64:25 15:25 20:4 20:12 24:20 65:1 65:4 66:8 limey [1] 16:3 26:1 mean [1] 22:14 22:15 modify [2] 29:17 66:10 66:22 limit [2] 46:25 70:19 LWD [2]32:17 32:19 23:7 32:7 51:3 64:9 59:18 59:22 module [1] knew.. [4] 13:10 limitation [1] 29:9 M[I] 30:24 57:9 means [1] 59:20 13:14 13:17 73:13 limitations [1] 58:8 Mac [1] 19:1 moment [1] 49:23 knewkul..,ly [1] limited [1] measured [1] 9:9 money [1] 39:10 71:9 magIc [1] 15:1 70:10 limits [4] 8:11 main [11] 53:19 measurements [1] month [1] 48:11 lrnewtt [4] 13:3 monthly [2] 4:18 10:] 29:10 70:]9 53:20 54:17 54:19 mechanical [1] 47:22 11:18 17:19 34:19 line [1] 54:19 56:17 56:19 29:14 58:5 22:14 24:24 · KuptII'Yk [14] 7:6 25:10 26:3 26:11 57:1 57:10 57:11 mechanism [1] 20:2 months [3] 55:12 7:24 8:17 11:6 55:21 67:24 57:13 mechanisms [2] 19:10 55:13 58:5 20:7 54:10 55:24 lined [1] 27:7 maintain [2] 4:24 19:22 morning [1] 2:3 55:25 55:25 56:8 liner [1] 34:22 29:25 meet [1] 45:15 3:13 7:18 30:9 56:19 56:20 57:2 44:18 maintailJing [2] 27:23 member [1] 30:10 43:25 52:12 58:8 44:19 44:23 44:24 12:15 L [1] 45:6 45:13 55:9 mentioned [5] 5:3 morning's [1] 3:17 73:12 lines [6] 25:7 maintenance [4] 29:24 23:13 62:24 63:12 most [10] 37:3 laheW [1] 33:5 15:22 35:5 35:7 46:4 34:5 38:14 56:14 64:13 44:17 45:13 54:2 lakes [2] 54:25 55:4 49:18 major [5] 7:17 met [1] 35:24 55:2 65:6 65:15 laqe [4] 15:19 17:25 liquids [1] 28:23 10:23 17:14 20:3 metering [1] 56:18 65:23 66:11 69:8 36:19 57:4 Lisburne [2] 16:4 33:8 methanol [3] 59:15 mostly [2] 12:4 l8lF1y [2] 10:10 19:1 makes [1] 40:17 59:16 59:18 47:3 11:17 listed [3] 7:18 manage [1] 29:16 method [1] 59:13 motion [1] 3:11 laraer [2) 11:1 35:11 64:5 manager [1] 3:19 Metro [3] 2:12 move [1] 23:6 26:23 live [1] 55:8 mandrels [2] 44:15 2:14 73:5 moved [1] 61:3 last [12] 6:6 7:7 living [1] 63:20 45:1 Mexico [3] 31:2 movmg [1] 32:22 18:25 31:5 31:8 38:8 40:4 43:17 loaded [1] 49:2 manifold [1] 60:20 43:16 53:3 MS [1] 1 :11 53:2 53:4 53:6 locally [1] 9:22 manifolds [1] 61:4 MI[2] 26:21 26:23 mud [3] 33:7 33:8 67:14 located [6] 2:6 manner [2] 26:5 MICHAEL [1] 1 :13 34:14 Lava [2] 2:11 2:7 4:21 7:23 55:11 microphone [1] 64:21 mudding [1] 68:23 73:8 20:18 54:14 map [9] 7:23 8:3 mics [1] 53:14 muddy [1] 16:3 Lauel [1] 73:12 location [91 7:23 10:9 14:8 17:4 middle [1] 53:17 muds [2] 34:6 68:19 Ie_ [1] 68:11 13:12 14:7 33:1 17:22 18:2 47:24 might [2] mudstone [1] 16:3 34:4 51:3 54:6 53:17 45:22 le..-r [1) 30:22 55:1 68:10 mapped [21 18:2 53:16 multi-lateral [1]26:9 leak-eft" [4] 41:8 locations [2] 6:7 18:7 Mike [4] 5:6 52:4 multiple [2) 25:24 41:15 67:18 68:2 18:25 marginal [5] 48:16 58:22 62:10 70:18 leak-efts [1) 67:25 log [10] 8:14 9:16 51:18 61:11 62:2 mile [1] 54:16 MWD [1] 32:16 · lea [1) 19:24 13:2 14:10 35:18 62:3 miles [4] 7:24 53:23 N[5] 1:6 1:6 least [4] 8:8 12:18 35:19 35:25 36:11 manne [2] 11:13 54:2 54:17 2:1 72:15 72:15 17:17 58:4 65:22 67:23 12:18 mill [1] 34:3 name [1] 3:19 4:15 leave [2] 32:14 33:9 logging [4] 32:16 Mark [4] 1:12 3:19 millidarcies [1] 19:16 4:19 4:22 5:10 leaVÏ411 [3] 33:11 32:17 32:19 36:17 4:1 18:14 millidarcy [4] 20:21 30:21 63:4 46:13 55:23 logic [2] 14:23 24:11 marker [5] 9:19 21:2 71:9 71:10 names [1] 4:17 M..... c..t :Reporting, Inc. Index Page 7 AOGC . CondenseIt TM . naming - pinch-out natlÚ.1lg [2] 4:25 59:11 6]:9 68:2 56:11 56:20 56:22 order[s] 2:18 2:18 people [4] 7:16 5:2 NPRA [1] 8:1 61:14 65:12 65:16 4:24 63:15 70:20 55:8 55:14 63:19 Nauk [1] 6:5 Nuiqsut [7] 8:16 71:15 73:7 73:10 original [1] 46:13 per [6] 13:3 27:20 natural [2] 16:14 27:14 27:15 29:23 oil-bearing [1] 8:18 originally [1] 21:21 46:25 47:9 48:18 · 71:25 53:22 54:8 56:1 oil-water [1] 10:14 otherwise [1] 26:7 70:16 natuJe [2] 32:20 number [19] 4:17 Oklahoma [1] 30:25 ours [2] 56:21 61:20 perforate [1] 15:7 32:24 6:2 6:3 6:3 old [1] 42:7 outline [1] 8:6 perforating [1] 48:4 near [3] 27:4 54:8 7:21 9:7 ]7:4 older [1] 65:11 outside [1] perforations [1] 50:20 19:23 21:14 22:17 55:21 63:20 perform [1] 32:12 25:9 38:4 47:20 once [6] 18:14 35:24 overall [4] 12:15 necesøari.ly [12] 3:5 54:24 57:23 58:10 38:5 38:23 41:23 31:15 45:9 46:7 performance [2] 20: 13 16:9 18:10 25:12 59:23 63:7 69:18 52:8 overlay [2] 46:2 25:14 27:17 27:25 18:3 28:7 28:12 38:17 numbers [1] 55:4 one [4S] 11:22 17:4 65:6 performed [1] 48:8 64:2 68:15 o [S] 1:6 1:6 17:6 17:22 20:14 own [2] 28:25 55:16 performing [2] 24:14 2:1 72:15 72:15 23:24 24:1 24:5 48:5 necessary [1] 23:4 25:24 26:5 26:10 owners [6] 6:9 Nec_Iit. [7] 8:1 0' clock [3] 1:8 26:16 28:8 32:21 22:10 23:1 23:5 perfs [2] 15:17 15:18 8:16 9:5 14:20 2:5 73:9 35:20 36:15 37:14 58:21 64:12 perhaps [7] 8:25 17:16 53:20 54:14 Oath [S] 4:8 6:23 37:15 37:16 37:16 ownership [2] 6:9 12:5 16:12 17:24 neeti [16] 5:4 23:11 30:15 43:6 52:18 38:11 38:12 38:13 29:7 45:20 49:13 64:9 27:5 29:11 29:15 objection [11] 7:10 38:16 39:20 40:4 owns [1] 6:13 period [6] 35:4 29:17 34:25 35:16 7:11 7:12 19:3 42:8 45:2 47:12 P[4] 1:6 1:6 46:22 47:12 48:12 41:25 59:12 59:22 19:4 19:5 31:10 47:12 48:14 49:23 2:1 72:15 51:20 56:10 65:1 65:24 66:4 31:11 53:8 53:9 55:22 56:19 57:13 packer [2] periodic [1] 3:13 68:23 71:24 53:10 57:15 57:21 58:15 44:23 periodically [1] 66:15 n~ [4] objections [4] 61:16 61:22 63:5 50:19 23:6 31:9 64:25 68:3 68:5 pad [18] 6:7 14:9 peripheral [3] 21:1 32:18 33:1 36:16 43:19 43:20 43:21 71:14 18:6 31:17 35:20 26:6 71:6 nelatively [1] 46:6 obligation [1] 35:21 ones [1] 17:14 37:5 51:22 54:2 peripherally [1] 66:12 net [4] 14:17 15:11 obtaining [1] 47:3 onshore [1] 51:8 54:3 54:17 54:19 periphery [2] 21:7 16:18 16:20 obviously [2] 63:17 54:20 58:10 61:21 71:9 Neve [1] 6:5 69:24 onto [2] 11:17 61:21 62:4 62:6 62:7 permafrost [8] 12:10 new [9] 23:16 23:20 OCCUT[2]44:21 48:1 oops [1] 45:18 66:4 12:23 13:5 31:20 34:24 42:7 43:16 October [1] 2:21 open [IS] 12:2 26:14 pad's [1]37:5 31:21 44:14 49:17 48:13 63:12 69:21 Oechsli [22] 32:14 34:22 44:8 pads [9] 36:21 36:24 50:17 · 70:7 1:11 44:18 45:5 45:9 54:1 61:15 61:16 2:10 7:11 19:5 45:11 46:13 58:7 permanent [1] 6:6 newly [1] 45:21 61:17 61:19 61:19 permeability [7] 31:11 37:12 37:15 58:15 64:18 71:24 61:24 News [1] 2:21 37:17 37:21 37:23 72:4 19:14 19:15 20:21 next [11] 4:24 12:3 38:1 39:12 40:3 page [2] 37:18 42:17 21:2 29:16 46:15 operate [1] 57:19 12:11 21:12 23:19 40:19 40:23 41:10 paper [1] 3:7 65:17 37:18 47:5 54:3 42:2 42:5 42:13 operating [1] 26:22 paperwork [2] 35:14 permit [4] 34:1 54:4 63:11 70:6 42:16 43:20 53:9 operation [2] 39:4 35:17 34:15 40:19 44:2 nice [1] 7:15 off [12] 32:23 42:21 67:19 part [12] 12:5 12:20 permitting [2] 35:2 nlJle [2] 2:5 55:12 47:4 56:11 58:25 operations [13] 5:6 12:22 20:17 21:3 40:11 niMlt [1] 5: 14 62:16 70:24 70:25 5:13 13:11 31:3 21:21 23:2 23:10 person [3] 64:20 71:2 71:3 71:8 43:25 44:5 47:25 35:11 37:4 45:8 66:25 69:9 nippk [1] 33:4 72:14 48:1 48:6 53:5 51:3 personal [1] ni""'" [1] 33:5 off-take [1] 29:16 53:5 53:6 53:7 participating [1] 13:13 nitF4wm [2] 49:13 offer [6] 4:3 6:20 operator [2] 60:10 4:24 pertinent [1] 40:9 49:14 7:1 30:10 43:1 63:19 particular [6] 3:10 petroleum [4] 6:13 nOl'MltI [1] 10:13 52:13 opportunities [4] 12:24 18:6 36:7 7:6 18:23 43:14 Nonh[4] 19:15 offices [2] 2:6 36:18 46:12 66:7 48:4 51:3 petrophysicist [1] 33:7 59:23 61:19 73:10 66:11 parties [1] 23:5 13:4 nortlleaøt [4] 10:11 official [1] 4:21 opportunity [7] 3:14 parts [S] 11:7 13:3 ph [6] 11:12 18:5 25:20 25:25 26:8 33:17 56:11 65:5 10:11 11:16 11:17 offset [4] 10:20 27:15 41:19 62:15 54:19 55:5 57:11 68:11 noI1llern [1] 11:13 11 :1 11:2 17:17 opposed [2] passed [1] 41:19 phase [12] no..... .ye¡;t [1] offsets [4] 10:14 60:14 21:1 10:12 61:1 past [3] 4:18 39:19 21:23 24:9 24:9 NoUI'y [2] 73:4 10:22 11:8 17:12 optimization [4] 43:16 24:12 24:12 24:13 73:17 offshore [3] 31 :1 19:11 25:21 26:19 pattern [S] 8:3 24:18 24:23 24:25 note [3] 2:4 3:11 43:16 51:6 26:20 8:12 22:6 26:3 25:1 25:3 51:14 often [1] 45:5 optimize [1] 21:10 45:15 phases [1] 20:17 nothitlg [1] 39:15 oil [3S] 1: 1 1:4 optimized [2] 27:1 patterns [3] 45:25 pick [2] 9:18 32:9 notiee [2] 2:20 2:6 2:17 5:2 39:25 46:6 46:7 picture [1] 59:2 48:11 7:22 7:23 7:25 option [4] penetrate [1] 45:22 piece [2] 3:7 · 8:3 8:4 8:7 24:12 40:13 Novetllher [1] 2:22 9:8 9:16 10:16 25:15 25:17 68:25 penetrates [1] 26:10 pilot [2] 60:13 61:1 nOW[14] 12:1 13:23 19:19 19:19 28:20 options [2] 19:23 penetrations [2] 8:23 pilots [2] 49:18 19:9 21:20 26:2 28:21 30:22 53:1 58:12 65:21 60:17 38:16 38:21 39:18 54:8 55:7 55:7 oral [1] 42:18 Penn [1] 18:23 pinch-out [2] 10:10 41:14 41:17 41:22 55:24 56:6 56:8 MctN c..rt Ieporting, Inc. Index Page 8 AOGC . CondenseIt TM . Pinched - recovery 11:16 Porcupine [2] 2:7 problems [10] 29:14 51:22 54:22 69:5 R[6] 1:6 1:6 PiBC_d [1] 10:11 73:11 29:14 29:15 31:19 69:13 69:21 1:6 2:1 72:15 pipe [2] 32: 18 44:20 porosity [10] 14:13 34:17 34:17 45:16 propOSIng [8] 31:21 73:1 pipelitte [3] 27:6 14:14 14:17 15:12 45:25 60:16 60:25 36:12 40:14 41:21 radioactivity [1] · 54:7 54:12 15:16 16:24 17:2 procedural [1] 42:6 41:21 51:14 66:21 35:19 place [8] 19:19 19:13 19:15 65:17 proceed [7] 4:1 68:12 radius [1] 45:23 21:9 22:25 23:20 33:12 port [2] 31:22 32:1 4:6 4:13 19:7 protect [3] 5:23 raise [6] 4:6 6:19 57:24 63:16 70:7 position [1] 70:9 23:8 28:5 43:23 49:16 49:17 6:22 30:13 43:4 placeci [1] 20:19 possibility [3] 27:10 proceedings [3] 2:11 protecting [2] 5:20 52:16 plait [59] 12:1 20:1 28:14 67:11 2:13 2:15 49:8 ran [1] 58:20 20:6 20:]6 21:5 possible [5] 27:5 process [10] 20:3 protection [8] 49:10 ranges [1] 10:21 21:8 21:13 21:15 38:24 48:23 60:11 22:6 22:19 28:21 49:12 50:17 51:13 ranging [1] 21:19 22:9 22:11 64:14 29:25 35:2 36:10 58:17 59:8 59:13 20:10 22:15 22:16 22:21 possibly [2] 54:23 38:6 59:4 59:6 59:20 rapid [2] 52:8 52:9 22:25 23:2 23:7 67:2 processing [4] 54:3 prove [1] 68:25 rate [1] 70:25 23:16 23:20 23:25 post-work [1] 48:8 54:21 55:20 56:7 provide [10] 3:14 rates [7] 45:24 62:8 24:7 25:8 25:11 potential [5] produc [1] 56:3 3:17 3:20 11:5 62:9 71:1 71:3 25:20 25:21 26:2 29:11 produce [3] 29:25 71:6 71:15 64:23 65:5 65:7 7:16 34:13 35:23 26:17 27:2 27:24 65:19 29:22 70:17 50:16 63:1 70:2 ratheT[1 ] 47:22 28:6 28:10 32:15 produced [2] provided [2] 33:25 ratio [1] 71:10 32:19 32:20 33:2 potentially [4] 15:17 27:11 33:11 34:4 35:12 22:23 22:24 46:1 56:10 48:16 ratios [1] 26:25 36:7 36:25 40:10 pound [1] 67:24 producer [3] 29:]7 providing [2] 4:2 ray [2] 9:18 9:20 44:10 54:22 54:23 pounds [1] 47:11 44:7 47:8 36:3 Re [1] 1:3 57:24 63:2 63:11 Power [1] 55:16 producers [2] 22:2 Prudhoe [9] 7:6 re-injected [1] 63:13 63:16 64:2 49:10 11:7 14:13 19:1 27:12 68:6 68:21 69:6 practice [2] 35:21 producing [10] 27:21 31:7 43:17 56:19 re-injecting [3] 20:14 69:13 69:14 69:16 51:10 58:8 58:13 21:6 56:13 69:21 70:7 71:16 practices [7] 5:12 29:10 44:1 47:9 re-injection [3] 48:13 48:17 50:14 pSI [1] 47:14 20:1 pl_ÏtII [1] 56:4 5:14 31:16 31:24 52:9 59:12 60:4 Pt [1] 19:1 20:14 27:10 pl_ [5] 19:10 19:11 32:4 32:17 63:6 production [20] 5:14 Public [3J re-perforating [IJ predetermined [1 J 1:2 32:16 35:5 38:21 31:2 34:17 44:11 73:4 73:17 48:5 plaBt [13J 27:7 34:14 45:1 48:1 50:15 publicly [IJ read [1] 53:21 69:18 27:7 54:4 54:21 prefer [2J 41:23 53:2 57:1 57:21 published [IJ 2:20 ready [IJ70:7 · 55:1 55:19 55:20 69:22 58:3 58:4 58:5 real [3J 2:3 16:22 56:6 56:7 56:8 prepared [1] 70:2 59:2 59:10 60:5 pumps [3J 56:17 53:13 56:16 56:24 57:3 present [5J 63:9 64:15 70:23 56:18 61:24 platf8I'M [1] 13:7 71:15 really [12J 10:22 55:25 23:22 32:4 32:19 purposes [IJ 27:22 15:1 26:16 55:22 play [2] 16:22 63:8 70:7 productive [1] 71:7 purSUIng [IJ 63:12 57:13 63:1 63:3 plelllN1'e [2] 2:4 presenting [1 J 24:12 productivity [1] 70:16 put [10] 9:2 9:25 63:8 64:4 64:7 72:9 pressed [IJ 3:21 profile [IJ 71:15 10:18 21:9 39:20 69:22 70:9 pl. [3] 33:13 45:11 pressure [26] 19:19 profiles [IJ 29:17 51:1 63:13 67:24 reason [6] 34:15 68:9 72:1 68:20 19:20 26:21 27:23 prograding [IJ 65:14 35:4 36:2 42:8 pl1llfÍ!lll [1] 46:9 29:23 29:25 33:13 24:5 putting [4J 13:15 46:8 62:24 plus [1] 33:15 33:21 33:22 program [2] 37:12 41:4 68:18 reasoning [1] 39:5 23:4 34:21 poi.t [17] 34:14 34:19 46:18 project [7J qualifications [6J reasons [3] 36:16 9:11 47:8 47:10 47:11 2:22 3:1 7:4 18:21 38:12 38:12 10:2 17:15 17:20 47:13 47:16 47:17 22:3 26:20 31:8 30:20 43:11 52:23 19:20 33:12 33:19 56:14 57:12 67:12 43:18 53:7 55:5 qualified [1] receive [5] 2:12 35:6 38:4 38:8 projected [1] 7:16 45:2 45:6 48:7 67:17 67:21 67:21 38:21 quality [4J 12:25 67:10 39:22 41:10 41:16 68:2 promising [1] 29:1 44:12 64:25 68:3 19:19 20:18 24:19 received [1] 30:23 68:5 pressures [4J 41:12 promote [2] 5:22 quantities [IJ 8:19 46:22 47:19 47:21 5:24 recess [1 J 62:12 poiMe4 [1] 10:5 pretty [6J 10:20 propagate [1] quarterly [IJ 58:11 recognize [3] 7:15 poiMs [1] 15:5 13:4 15:25 16:18 41:13 quartz [1 J 9:20 51:6 66:6 poel [38] 1: 4 2:16 66:3 68:25 proper [IJ 69:23 questions [21] 3:5 recombining [IJ 28:23 2:17 4:15 4:25 prevent [2] 5:22 properties [IJ 19:10 3:6 3:7 3:14 recommending [3J 5:2 5:2 5:9 39:15 property [2J 19:13 6:17 10:17 30:3 46:18 47:6 47:18 5:10 5:10 5:22 previous [IJ 60:11 30:5 42:12 50:8 record [12J 7:18 7:21 7:22 34:2 proposal [5] 27:13 50:22 50:25 58:17 2:2 7:22 7:23 7:25 previously [1] 23:18 27:25 35:3 41:9 62:15 62:20 62:21 40:7 42:21 42:22 8:3 8:4 8:7 primarily [IJ 43:17 58:20 64:16 64:18 69:4 62:16 62:17 62:18 9:7 9:7 9:16 primary [5J 69:9 71:22 71:24 72:4 72:5 19:23 propose [4J 5:17 9:17 10:1 10:16 quick [1 J 72:12 72:14 11:10 12:7 45:10 46:7 59:13 33:8 35:1 35:22 57:21 recorded [IJ 2:11 · 13:17 59:19 proposed [21J quickly [2] 27:5 19:11 29:8 29:23 5:9 recover [1 J 55:10 34:11 36:8 48:2 principal [1 J 38:12 5:22 8:3 19:11 27:7 63:4 63:4 65:16 priority [IJ 5:19 21:12 21:13 22:11 quite [6] 18:4 19:14 recovered [IJ 47:13 pOMf)f' [1] 24:19 problem [3] 38:1 22:21 23:7 25:8 19:17 38:8 71:6 recoveries [2] 20:13 60:6 68:2 34:4 34:23 38:7 71:11 20:15 p08ll8Øt [1] 20:13 41:2 42:7 48:11 recovery [19J 5:24 M«*e c..t Ileporting, Inc. Index Page 9 AOGC . CondenseIt TM . recyclable - short-term 19:10 19:22 19:24 requested [2] 34:11 16:16 18:5 18:11 59:22 60:11 61:11 12:13 12:23 15:16 20:2 20:3 20:9 48:3 24:10 30:13 35:6 63:19 63:24 63:25 15:16 16:19 17:4 20:11 21: 11 22:17 requesting [5] 35:11 36:21 38:2 38:21 Sag [10] 10:24 14:3 17:25 18:6 20:4 22:21 29:18 29:24 38:5 46:24 47:25 39:13 39:18 41:10 14:7 14:16 15:18 20:10 38:13 38:15 · 29:25 48:2 69:5 58:11 43:4 50:7 52:16 16:10 16:17 16:22 46:5 52:7 52:8 69:12 69:21 70:12 requests [1] 29:11 53:17 53:18 53:22 17:1 68:18 53:16 53:25 54:5 recycl_1e [1] 34:7 53:24 54:3 54:18 Sak [1] 34:10 54:15 54:24 56:23 reqwre [4] 36:11 54:25 55:1 59:11 61:16 64:23 65:5 recycle [2] 26:23 38:11 51:9 51:10 60:18 62:10 68:2 Sakoonang [1] 54:25 66:19 67:15 67:23 34:5 required [31 35:19 68:13 sales [3] 55:24 56:9 72:10 red [3] 8:5 12:13 36:15 55:6 rights [1] 5:23 57:22 seemg [2] 28:13 47:24 red1lee [5] requirement [4] 38: 10 ngs [1] 25:13 sampled [1] 47:21 37:4 21:14 46:8 51:7 58:12 risk [2] sanction [1] 26:20 segment [1] 44:9 26:5 32:21 32:25 20:4 22:24 32:25 reserve [1] 59:2 river [21]4:20 4:21 sanctioned [1] 23:1 seismic [2] 10:25 red1lCtion [1] 35:14 reserves [4] 25:25 4:22 4:23 5:1 sand [8] 14:14 14:17 17:25 26:6 45:19 69:19 7:22 7:24 7:25 15:11 15:14 15:15 select [1] 19:25 refereRCe [I] 47:18 reservOIr [38] 3:22 8:2 8:5 8:24 16:20 17:1 44:21 sensitive [2] refi"iag [1] 53:3 51:10 3:22 4:19 5:2 8:25 10:24 14:4 sands [5] 11:12 51:12 reflect [1] 69:12 5:5 5:12 18:15 14:7 14:16 15:18 12:15 15:20 65:9 sensitivity [1] 51:5 reflector [2] 10:25 19:9 19:10 19:13 16:10 16:17 16:22 65:15 11:1 26:14 26:21 27:23 17:1 53:20 53:23 sandstone [10] sent [1] 44:3 8:15 reprtl [1] 63:3 28:3 28:25 29:3 54:8 54:15 55:22 8:16 8:19 9:21 separate [1] 56:8 reg~ [1] 29:15 30:2 32:8 65:21 10:6 12:6 14:2 separation [3] 56:7 5:13 32:10 34:13 34:19 nvers [1] 54:25 14:12 14:16 14:20 56:16 58:15 regÎeIMÙ [2] 6:10 35:25 36:13 36:20 road [2] 54:11 54:12 sandstones [2] separator [1] 57:1 11:11 36:24 44:4 45:16 8:17 regiMBr [1] 47:16 46:2 46:17 47:7 roads [2] 55:15 55:15 65:13 sequence [9] 12:9 47:10 47:17 56:14 ROBERT [1] 1:11 sandy [1] 12:19 12:16 12:19 14:4 regalMetl [1] 41:14 57:25 59:1 67:16 rock [4] saturation [3] 64:22 65:5 65:14 16:2 16:2 8:24 re~ [2] 41:22 67:16 20:18 24:19 8:25 19:18 65:20 65:22 42:7 resistivity [3] 9:19 role [1] sequences [1] 65:13 16:23 saw [2] 6:6 16:9 re~ [5] 2:24 9:20 45:21 roughly [1] senes [2] 62:19 38:7 38:11 51:6 resolving [1] 38:22 says [3] 10:6 40:12 64:18 61:17 19:20 39:23 46:4 47:23 41:3 rei__ [1] resources [3] 5:20 54:16 56:3 57:9 scale [4] 17:21 17:24 servIce [4] 3:21 63:18 5:21 71:25 20:8 27:8 35:25 · rel..-l [2] 40:20 route [2] 28:17 55:16 18:4 46:4 Services [1] respect [1] 40:5 routine [1] 3]:6 63:2] 51:15 scenano [1] 68:20 rellltive [6] respond [1] 64:21 routing [1] 54:7 schedules [1] 38:17 set [10] 12:1 31:17 51:3 31:20 32:10 33:14 61:10 67:11 67:11 responds [1] 45:4 rows [1] 22:1 scheme [2] 24:2 33:21 44:12 50:14 70:10 72:1 result [4] 19:25 royalties [1] 58:25 69:5 65:22 73:14 relatively [3] 47:20 22:16 22:20 26:13 royalty [3] 6:9 Schrader[4] 12:9 sets [1] 45:10 51:12 61:5 results [2] 21:18 57:25 58:21 12:20 12:22 34:9 setting [3] 11:11 reJlll8ÏttÏill [1] 20:24 21:25 rule [22] 7:21 7:21 sCIence [1] 30:23 38:18 50:13 re~ùer [1] 21:18 resupply [1] 59:16 9:7 29:3 29:3 screen [2] 10:18 seven [3] 35:6 re:DilMe [1] 32:24 returned [1] 29:23 29:21 34:11 34:11 67:5 38:22 47:14 re_val [2] 48:16 Revenue [1] 69:4 35:10 44:5 44:5 screen-out [1] 68:19 seventh [1] 5:13 51:4 reversal [1] 45:4 44:6 46:18 47:25 sea [1] 55:23 several [3] 48:9 63:4 63:4 13:4 Te1III8ve [2] 51:17 revised [6] 21:13 63:5 63:5 63:6 Seabee [3] 12:5 58:5 60:5 61:23 22:16 25:8 25:20 64:1 64:6 12:14 34:9 shale [9] 12:6 12:9 re~vod [1] 64:8 26:16 28:7 rules [13] 2:16 seal [1] 73:15 12:14 12:18 12:19 reJll8VHII [l] 64:4 revision [2] 28:10 4:25 5:9 5:17 seat [1] 42:24 14:5 14:18 14:24 re~[I] 3:2 28:11 5:22 8:4 19:11 seawater [1] 54:7 15:18 rei- ~j,tlous [1] 66:5 rich [2] 9:21 28:22 29:2 36:8 42:17 second [10] 5:10 shales [2] 10:11 Richards [26] 63:2 63:7 64:13 65:14 le~r..htl [1] 47:21 1:14 21:1 21:23 24:18 5:7 49:25 50:3 run [3] 32:7 32:15 32:2 34:20 35:23 shaley [1] 12:16 Repener [1] 73:5 50:23 52:11 52:12 35:8 54:21 54:23 69:1 shall [1] 36:11 repoÂ : [3] 2:12 52:15 52:19 52:22 IUDmng [2] 50:15 section [19] 3:22 shallow [1] 11:13 47:19 73:5 52:24 53:13 57:6 58:6 4:19 5:4 5:5 shallower [1] 57:8 57:18 57:21 11:2 1etJ..:.\..oent [2] 24:13 runway [2] 55:12 5:7 8:10 11:2 46:20 58:22 59:8 60:2 55:15 17:11 18:15 19:9 Shared [1] 31:6 ~ive[2] 60:13 60:16 60:19 S[4] 26:14 30:2 30:8 sheet[l] 17:1 60:24 61:8 61:15 1:6 1:6 47:17 53:7 62:5 2:1 72:15 32:8 32:13 35:13 shipping [1] 56:17 repAo33ts [2] 47:7 rig [2] 24:5 Sadlerochit [1] 50:12 44:19 56:16 66:3 shoe [5] 34:16 34:18 · 69:15 32:23 sections [1] 8:4 67:12 67:12 67:22 reqtl88t [11] ng-up [1] 33:2 safety [22] 5:20 secured [1] shop [1] 55:8 34:11 right [39] 2:9 31:3 38:15 44:5 33:17 34:20 35:3 35:7 2:10 44:14 45:2 48:10 sediments [2] 11:10 short [5] 42:19 46:1 35:10 35:18 36:3 4:7 6:22 9:15 48:13 48:16 49:5 11:13 51:20 62:12 70:24 58:2 63:24 63:25 9:25 10:6 12:13 49:8 49:18 50:18 short-term [1] 71:23 13:20 15:11 16:13 see [30] 7:16 11:4 59:2 51:4 51:9 51:14 MetN c..rt Reporting, Inc. Index Page 10 AOGC . CondenseIt TM . show - Texas show [6] 9:5 29:4 10:20 18:1 27:16 started [2] 41:1 substantially [2] 30:11 30:18 43:1 29:10 35:5 47:6 47:20 56:5 56:24 41:7 54:23 59:11 52:14 52:21 65:1 56:23 59:15 state [13] 3:1 6:10 subsurface [13] 44:14 65:2 sooweø [2J 17:3 smaller [3] 11:2 7:3 7:16 18:20 45:2 48:12 48:16 system [6] 33:3 · 36:5 45:13 57:2 18:23 30:20 43:11 49:5 50:18 51:4 33:4 33:6 33:14 showiøg [IJ 12:11 solids [2] 13:2 43:12 52:23 52:24 51:7 51:9 51:14 55:25 60:11 SOOWR [4J 9:17 68:20 73:3 73:4 61:10 63:24 63:25 systems [5] 33:7 18:2 45:7 47:24 solution [2] 21:6 statement [1] 72:8 success [1] 13:15 33:8 58:14 60:14 shows [4] 8:3 28:21 STATES [1] 73:2 such [4] 38: 18 51:24 61:1 14:6 54:4 68:17 sometime [3] 4:24 static [6] 46: 18 46:21 63:9 70:23 T[4] 1:6 1:6 Shllhlik [3] 14:14 70:1 71:3 47:3 47:12 47:15 sufficient [1] 36:4 73:1 73:1 15:21 16:3 somewhat [5] 16:1 47:19 suggest [1] 47:12 table [1] 3:8 shut [2] 45:3 57:18 28:15 35:20 68:19 statics [2] 46:23 suite [4] 35:24 37:2 tables [1] 2:8 shllt-iø [6] 5:13 69:24 46:25 66:1 66:21 taking [3] 3:13 47:11 47:14 48:9 soon [1] 38:24 stating [1] 65:9 summanes [1] 48:8 51:20 61:10 57:20 64:1 sorry [1] 37:25 steps [3] 51:20 51:23 summaTlze [2] 62:19 tapered [1] 50:16 side [2] 6:2 6:11 sort [4] 13:16 20:21 61:12 62:23 tapering [1] 70:25 sideVaek [31 29:12 49:19 66:18 still [3] 20:4 48:7 summary [4] 5:4 target [2] 25:24 45:12 46:10 sorted [2] 9:21 48:22 5:9 62:20 64:11 50:20 sidevøck:iøg [1] 29:13 9:22 stimulating [1] 48:5 summer [2] 23:19 Tam [1] 13:12 sicletreeks [8] 29:18 sound [1] 55:11 stop [2] 35:9 46:1 70:6 TD [4] 35:19 38:23 44:4 45:8 45:19 Sounds [1] 29:1 stopped [1] 33:18 sumps [1] 61:18 39:20 39:24 45:20 45:24 46:1 source [3] 11:13 storage [1] 32:21 superintendent [1] TD-ing [1] 38:21 48:6 28:25 46:21 stored [1] 33:1 53:6 team [3] 30:22 53:7 sipificaet [5] 12:18 sourcing [1] 28:19 StOTm[I] 61:17 supervisor [1] 53:5 66:12 14:9 16:23 52:5 south [3] 11 :23 53:18 straight-forward [1] supplied [3] 29:22 technical [6] 4:2 56:10 sipifieaMly [1] 54:8 58:15 34:15 71:18 23:3 23:11 23:15 southwest [1] 11:23 stratigraphic [2] supplies [1] 55:14 36:1 69:23 27:18 technically [1] 7:16 sil... [2] 12:10 spaced [2] 66:2 10:10 17:8 supply [6] 35:25 12:21 66:4 stream [2] 28:24 40:14 41:3 41:17 technologies [1] 34:25 simpk [1] spacIng [20] 5:11 55:22 55:16 59:16 technology [1] 45:21 58:14 20:23 20:25 21:4 Street [1] supplying [1] 5:16 telecommunications sÍ11ll(lMeÏty [1] 45:7 73:11 · 21:15 21:18 21:19 strength [1] 67:24 support [5] 5:17 [1] 55:17 si.mplifïed [1 J 56:22 21:24 21:25 22:1 strike-dip [1] 55:6 55:12 55:13 ten [1] 63:3 s:i.mply [1] 7:21 26:18 29:3 29:5 11:10 63:15 sÍD!N~s [1] 29:7 29:20 45:15 string [4] 12:3 surface [29] 12:1 tenth [1] 5:15 40:24 46:5 46:6 46:8 33:14 50:15 50:16 12:13 31:20 31:21 terminology[1] 15:2 siRlIe [2J 63:5 strings [1] 33:20 31:22 31:25 32:22 terms [14] 11:10 31:22 33:2 spacIngs [1] 36:14 strip [1] 54:18 33:12 33:22 38:18 14:22 16:23 23:25 site [1] speak [4] 6:18 stripping [1] 28:22 38:20 44:11 44:13 28:16 36:19 38:13 24:21 32:24 40:1 44:2 44:3 45:3 48:10 48:12 38:18 55:21 58:13 35:22 35:23 54:15 speaking [1] strong [2] 16:2 48:20 49:4 49:8 58:19 61:9 66:23 54:22 56:25 51:13 60:4 49:18 50:13 51:2 67:9 sites [IJ 20:19 specific [1] 50:5 structure [5J 10:9 52:2 53:16 59:22 test [15J 33:13 33:21 si~ [1] 66:16 specifically [1] 44:3 11:17 14:8 17:4 60:11 64:9 67:22 34:13 34:14 34:25 sitaMÎ8B [2] 46:11 speech [1] 40:24 47:23 67:25 35:4 38:22 39:22 60:9 spend [1] 38:4 studies [5J 19:25 surprised [1] 16:9 39:24 39:24 41:15 sIX [4] 26:13 32:22 spike [1] 70:24 22:23 23:11 23:15 surrounding [2] 51:5 58:11 65:11 67:18 46:25 48:11 spill [1] 51 :24 28:4 54:6 68:2 sixth[l] 5:12 split [1] 53:19 study [3] 20: 10 21:9 surrounds [1] 7:25 tested [4] 31:24 25:19 33:20 38:5 67:18 slia [10] 37:13 spokesperson [1] subject [1] 16:1 surveillance [3] 5:12 testifying [2] 53:12 37 :15 44:7 47:5 3:16 submit [4] 44:4 46:17 64:19 54:4 56:23 57:21 35:11 surveys [1] 32:16 64:20 67:5 67:6 ss [1] 73:2 36:3 40:20 41:24 testimony [20] 2:17 sli_ [2] stable [2] 58:6 submittal [1] 72:2 suspect [1] 71:24 2:25 3:17 4:2 42:18 58:9 suspend [1] 33:12 4:3 4:6 5:16 58:18 submitted [4] 40:8 sl~y [3J stage [3] 31 :22 32:2 40:11 40:16 40:17 suspended [1] 33:18 6:17 6:20 18:15 16:21 30:2 30:11 31:15 45:10 submitting [1] sustain [1] 70:23 50:14 57:2 41:22 34:3 42:9 42:18 Slope [101 6:10 stand [11 39:8 subsea [21 12:2 sustained [11 70:25 43:2 50:23 52:14 13:11 19:15 31:24 standard [1] 44:16 12:14 swap [1] 32:13 70:9 32:4 33:7 57:15 standpoint [1] 46:5 subsection [1] 40:4 swear [1] 4:5 testing [8] 38:14 · 59:23 60:10 61:19 start [8] 15:8 22:3 subsidence [2] 31:18 sweep [1] 46:2 39:16 48:11 48:14 sl<*ø4 [6] 34:22 22:6 22:7 27:7 31:19 switch [31 27:8 49:5 58:4 58:20 44:18 44:19 44:20 54:18 63:8 63:24 substantial [3] 54:24 28:9 53:14 72:1 44:24 45:6 start-up [7] 27:4 55:3 61:22 tests [4] 32:12 35:9 slow [1] 14:25 27:5 27:12 62:25 sworn [11] 4:3 41:8 58:1 4:11 6:20 6:25 small [9] 10:13 10:14 63:3 63:16 64:15 Texas [4] 6:13 M... c.wt Aeporting, Inc. Index Page 11 AOOC . CondenseIt 1M . thank - wells 30:24 30:25 53:3 topic [1] 46: 17 32:]8 33:17 35:25 using [9] 4:19 14:22 water [30] 8:24 thaK [35] 3:18 topics [2] 7:18 36:18 39:4 56:18 31:17 33:2 36:21 8:25 12:25 13:6 3:24 4:10 7:13 19:8 typical [3] 33:7 49:12 56:15 57:22 13:7 15:2 19:17 7:17 10:8 11:24 Torok [13] 8:17 44:7 44:25 57:25 19:24 20:1 20:4 usual [1] 2:23 20:6 21:5 22:3 · 18:12 18:13 19:3 8:17 12:5 12:16 typically [31 40:22 19:8 23:24 25:18 13:5 65:7 65:8 41:16 56:20 utilize [2] 21:6 27:1 27:3 27:6 30:4 30:17 31:9 65:9 65:11 65:13 ultimate [8] 27:6 27:8 27:10 29:24 5:24 45:24 55:10 55:23 31:12 31 :14 37:11 65:14 65:25 66:7 utilized [1] 40:2 43:8 43:19 6:7 20:2 22:17 22:4 56:9 56:10 56:18 43:24 52:3 52:20 total [4] 13:2 41:14 22:20 69:12 69:21 vacuum [1] 61:24 59:11 60:5 61:17 53:8 64:16 64:17 46:20 53:3 70:12 valve [18] 33:15 62:10 71:15 66:23 69:3 70:8 touch [2]7:19 13:23 unassisted [1] 48:20 33:16 33:22 33:23 watercuts [2] 52:5 71:13 72:9 72:11 towards [1] 11:18 under [16] 24:9 44:14 45:2 48:10 52:9 72:13 town [1] 3:22 27:2 27:24 28:6 48:13 48:16 49:3 waterflood [7] 20:12 thaKS [6] 4:12 tracing [2] 50:17 29:3 31:23 34:11 49:5 49:9 50:18 20:13 21:5 22:18 13:22 33:24 42:2 61:2 35:1 35:10 35:12 50:18 59:22 60:14 45:22 46:7 52:8 52:10 71:21 tracks [11 36:5 36:8 36:12 60:22 60:24 waterline [1] 20:7 thaw-[l] 50:16 6:3 40:4 44:6 69:5 valves [10] 44:5 tract [1] 59:7 underground [2] 49:18 51:4 51:7 waterways [1] 51:24 the.øelves [31 3:16 traditional [1] 47:14 2:18 53:15 51:9 51:15 59:24 ways [1] 21:10 61:16 61:24 train [6] 56:22 underneath [1] 61:11 63:24 63:25 week [3] 35:4 38:11 thereafter [1) 57:14 37:5 58:12 57:15 57:17 58:9 understand [3] variability [1] 71:12 38:16 17:16 thick [8] 12:9 12:10 58:15 22:8 49:19 variety [1] 53:5 weeks [6] 38:6 12:16 14:4 14:25 training [1] 38:9 56:25 72:4 15:9 15:18 65:14 31:3 Undoubtedly [1] VarIOUS [1] 18:25 72:4 72:12 thielE1I8ss [5] 10:21 transcribed [1] 73:12 66:19 verification [1] 41: 18 weigh [2] 57:5 16:17 16:25 20:21 transcript [1] 2:13 undue [1] 35:17 verifications [1] 57:7 21:2 trap [1] 10:10 Union [1] 6:13 41:8 weight [2] 34:14 thi. [2] 12:15 12:21 trapped [1] 45:20 unit [15) 4:21 4:21 verified [1] 33:21 49:11 ~[1] 51:19 tree [3] 33:16 33:16 4:22 4:23 7:24 versus [5] 21:21 well-by-well [1] thini[2] 5:11 17:23 33:23 7:25 8:5 8:24 27:20 33:20 42:7 65:24 thOVllR [2] trending [1] 10:12 9:1 23:2 23:5 59:2 wellbore [3] 27:13 35:15 65:16 65:18 34:6 60:15 triassic [4] 7:20 65:21 vertical [9] 14:25 44:22 46:16 thotø._ [I) 70:18 9:4 13:23 14:3 15:19 20:24 21:4 wellbores [2] 31:19 UNITED [1] 73:2 21:22 35:12 37:9 · thnJe [10] 7:17 trip [3) 4:16 39:20 units [1] 29:5 47:15 61:3 35:15 24:2 25:2 31:5 39:22 wellhead [11] 33:3 54:2 54:17 54:19 trips [1] 39:25 University [6] 7:8 vessel [2] 57:2 33:4 33:5 33:14 7:9 7:15 18:24 57:8 56:12 56:16 56:20 trouble [1] 39:10 43:12 52:24 vessels [3) 33:22 33:22 49:8 thrEMJIIÒ [14] 8:2 trucks [1] 56:17 49:17 51:21 60:21 61:24 unless [1] 36:1 56:20 56:21 62:2 10:19 10:24 11:3 16:6 17:7 17:10 true [3] 37:8 39:17 unpottable [1] 13:6 viable [1] 36:9 wellheads [2] 49:20 26:23 32:8 33:3 68:5 up [37] 3:7 3:11 view [1] 54:13 60:7 34:6 50:17 52:8 try [2] 34:25 68:21 5:8 9:24 9:25 village [2] 29:23 wells [96] 6:2 66:3 trying [1] 59:18 10:4 10:18 11:2 53:22 6:5 6:6 16:25 thr;ß~- :.;:- 3&t [2] 3:13 tubing [7] 32:15 14:6 15:20 16:5 volcanic [1] 12:20 20:21 20:22 20:23 46:23 44:15 45:13 48:5 17:7 17:10 17:11 20:24 20:24 20:25 threw [I) 50:19 70:19 70:19 17:14 27:7 33:4 volume [3] 27:16 21:3 21:4 21:14 17:10 turbidite [1] 36:17 37:4 37:13 27:17 61:22 21:16 21:18 21:20 thmws [1] 65:19 10:13 42:23 45:17 48:4 volumes [6] 26:24 21:20 21:22 21:24 tie [2] 54:9 55:25 turbine [1] 57:12 49:2 49:19 53:19 40:24 41:11 41:13 22:18 24:4 24:8 tight[l] 68:18 turbines [1] 56:13 53:20 54:5 54:13 56:2 57:22 24:14 24:20 24:22 times [2] 39:25 47:1 turn [3) 6:17 30:7 59:9 59:24 60:12 W[l] 1:10 25:2 25:9 25:10 timi. [2] 50:23 64:18 64:20 64:20 WAG [2] 26:24 25:23 25:24 26:2 39:1 67:5 68:20 26:2 26:3 26:5 39:23 TVD [1] 12:2 70:11 tiIJPÏtll [I) twin [I) 44:25 up-dip [2] 10:10 wait [1] 69:22 26:13 27:12 28:12 70:24 11:15 29:6 29:12 29:13 to~ [10] 2:4 two [30] 6:6 8:23 update [I) 66:16 WaIve [1] 40:5 29:14 29:19 32:20 2:11 3:23 4:16 11:22 20:16 20:18 waIver [3] 39:2 32:23 33:7 33:10 4:20 5:16 18:16 22:14 24:1 25:4 upper [9] 8:15 39:6 39:12 33:11 37:2 37:6 30:11 72:5 72:13 25:5 26:4 27:12 12:5 12:8 12:19 37:9 44:1 44:13 waIvers [1] 35:9 ~r[2] 29:2 31:8 35:4 14:3 14:16 14:19 45:1 46:19 46:20 61:5 36:21 36:24 37:1 37:4 70:19 wall [1] 12:14 71:21 47:1 47:4 48:2 38:2 38:5 53:6 uppermost [I) 8:15 warehouse [1] 55:8 48:10 48:13 48:16 toM [1) 57:9 54:1 55:23 55:24 upside [2] 20:13 wash [2] 34:5 55:9 48:17 48:19 49:4 too [2) 4:16 46:5 57:10 57:10 59:19 53:21 washing [2] 34:4 49:13 49:14 49:16 · took [I) 67:17 65:11 72:4 72:4 USDWs [1] 34:1 55:11 50:15 51:19 52:5 tools [11 32:16 72:12 used[6] 32:18 52:9 54:22 56:15 two-week [1] 38:10 33:18 waste [6) 5:22 57:20 57:24 58:3 top [10) 5:19 9:18 40:12 40:17 42:1 7:20 13:23 13:25 9:18 10:9 12:23 type [14] 8:14 9:16 55:11 14:1 14:10 58:9 58:10 58:13 14:7 31:22 32:9 12:12 14:10 23:25 59:9 59:10 59:12 uses [1] 56:12 wastes [1] 55:12 60:3 60:4 60:6 34:9 47:23 24:2 26:3 26:13 MøtN Cewt hporting, Inc. Index Page 12 AOOC . CondenseIt I'M . west - zones 61:4 61:11 62:2 31:6 31:8 43:15 63:25 64:5 65:12 43:16 53:1 53:4 65:23 66:2 70:17 53:5 53:6 60:6 70:21 73:4 yet [2] 13:20 59:7 · west [1] 7:24 10:13 yourself [4] 4:10 34:10 53:21 54:14 6:25 30:17 52:20 54:17 65:15 zone [19] 14:2 14:3 western [I] 8:2 14:5 14:11 14:17 WHEIlEOF[I] 73:14 14:18 14:19 14:23 witie[l] 58:15 15:1 15:2 15:4 wi. [I] 21:12 15:6 15:23 16:6 32:11 32:13 32:17 willteT[3] 55:14 34:8 34:9 59:17 64:13 zones [6] 29:16 wirelit1e [I] 58:1 50:21 67:10 67:20 wi...... [I] 61:10 68:7 68:8 wislt [14] 2: 12 2:25 4:2 6:20 7:1 18:17 30:10 30:18 43:1 43:8 51:17 52:13 52:21 62:20 wishes [1] 72:1 wislmlg [I] 72:7 withitt [9] 4:23 8:5 8:9 8:12 12:15 44:12 48:2 56:6 65:13 withMtt [8] 33:4 33:5 35:17 46:6 48:3 48:6 55:2 55:7 witBess [12] 4:3 7:1 7:14 18:18 19:7 30:18 31:13 · 43:9 43:23 52:21 53:12 73:14 w~RMi [1] 37:18 WOl'. [I] 39:20 work-ever [2] 5:13 44:5 work-overs [2] 33:5 43:25 worked [6] 7:5 7:6 18:24 30:24 31:4 53:1 works [1] 23:19 WOl'W [2] 39:25 72:11 ~ [2] 5:7 60:11 wr.,..d [I] 59:24 'WI ~~~'Il [2] 59:25 61:2 write [1] 3:7 written. [I] 72:1 wrðlll [I] 65:9 year [26] 4:24 6:6 7:7 21:12 24:1 24:1 24:2 25:22 43:18 46:25 47:8 47:10 47:12 47:13 47:14 47:21 48:14 55:3 55:13 58:3 · 63:1 63:10 63:11 64:15 67:14 71:4 yeat'S [19] 7:5 18:24 18:25 24:5 24:10 25:2 25:4 25:5 30:24 31:4 MetN Cewt Iteporting, Inc. Index Page 13 #2 . . December 3, 1998 Commissioner David Johnston Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501 Subject: Application for Disposal Injection Order Colville River Unit, North Slope Basin Dear Mr. Johnston: ARCO Alaska, Inc. submits for your review and action, this ~dated application for a disposal injection order to authorize injection of RCRA exempt drilling and production wastes into strata within the unit boundary. The application was prepared in accordance with Title 20, Chapter 25.252. This copy includes the property owners and operators affidavit as Exhibit 15 and corrects a number of errors in the initial application dated November 2,1998. c Inquiries regarding clarification may be directed to either Mike Stahl or Doug Chester at this office. Sincerely, /VVt~ ~ t;-Mark M. Ireland Alpine Development Manager 'v\~~"v \)~ f) Lr ¡" ..' r.. r: \" C f F D.S 4~ PJaskë: '" ~ i..'., ~:OI'Jr;jS¡¡Wf¡ A~CnOr2'1 , ..~ e . Application For Disposal Injection Order Alpine Development Project Colville River Unit North Slope Basin 20 ACC 25.252 December 1998 20 AAC 25.252 (c) 1 (c) 2 & 3 (c) 4 (c) 5 (c) 6 (c) 7 (c) 8 (c) 9 (c) 10 (c) 11 (d) & (e) (h) Exhibits 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 e e Table of Contents Well Locations Surface Owners and Operators Geologic Details Well Logs Well Construction Waste Sources and Characteristics Injection Pressure Waste Confinement Formation Water Salinity Aquifer Exemption Request Mechanical Integrity Wells Within Radius of Investigation Page 3 4 5 10 11 16 18 19 22 26 30 31 Alpine Project Area Surface Facilities Spider Map - Proposed Well Courses Type Log - Nechelik #1 Geologic Cross-section Seismic Section Structure Map - Top Confining Zone Structure Map - Top Injection Zone Structure Map - Lisburne Formation Base of Permafrost Well Schematic Well Head Schematic Well WD-2 Fault Picture Aquifer Exemption Area Affidavit of Notice to Surface Owners 2 e e Well Locations 20 AAC 25.252 (c) 1 Exhibits 1 and 2 show the unit boundary and the surface facilities that will be located in the Colville River delta. Exhibit 3 is a spider map showing the proposed development plan for the central facilities pad. Field development will require 92 wells with approximately 46 drilled from this pad. Surface casings of the development wells will be set below the West Sak formation at approximately 2400 feet. The first well to be drilled will be disposal well WD-2. It will be directed in an east-southeasterly direction as shown. The spider map shows three disposal wells; WD-l at an azimuth of 69 degrees, WD-2 at 104 degrees, and WD-3 at 322 degrees. WD-1 may be drilled as a backup, but it is not anticipated that WD-3 will be drilled unless reservoir or well mechanical problems impact the utility of the first two. The only existing wells near the disposal area are exploratory well Bergschrund 1 and development well CDl-22. Neither well reaches the top of the disposal interval, which is at approximately 8640 feet, subsea. 3 e e Surface Owners and Operators 20 AAC 25.252 (c) 2&3 The State of Alaska is the only surface owner within 1/4 mile of the disposal wells. No other operators are in the development area; therefore, no copies of the application need to be distributed other than to the state Department of Natural resources. The State of Alaska John Shivley, Commissioner State of Alaska, Department of Natural Resources 400 Willoghby A venue, 5th Floor Juneau, Alaska 99801-1796 Three land owners near the unit boundary are several miles away. They are: Kuukpik Corporation Joe Nukapigak, President P.O. Box 187 Nuiqsut, Alaska 99789-0187 Lydia Woods Sovalik P.O. Box 75 Nuiqsut, Alaska 99789 Bureau of Land Management Thomas J. Allen, Director, Alaska State Office 222 W. 7th Avenue #13 Anchorage, Alaska 99513-7599 4 e e Geologic Details Type Log, Cross Section, Structure and Stratigraphy 20 AAC 25.252 (c) 4 Introduction The geology of Permo-Triassic and Jurassic age sediments within the Colville River Unit area is described with specific reference to the proposed injection and confining intervals. Horizons and formations have been correlated westward from the Prudhoe Bay and Kuparuk Fields. Nomenclature from both the fields is applicable for the Alpine area. The horizons/formations can be correlated regionally and are shown on the type log and regional cross-section (Exhibits 4 and 5). The intervals of interest comprise clastic rocks of the Kavik, Ivishak, Shublik, Sag River, and Kingak Formations, in ascending order. A seismic section is presented as Exhibit 6. Structure maps on key horizons are presented in Exhibits 7-9 with the locations of the disposal wells noted. The Jurassic and Permo-Triassic sediments comprise the Ellesmerian sequence characterized by marine transgressive-regressive cycles deposited on a slowly-subsiding passive-margin ramp to the south with a broad, stable platform to the north. The Permo- Triassic Ivishak formation consists of lowstand fluvial-deltaic-marginal marine deposits that accumulated along the south-facing Ellesmerian ramp. Triassic transgression blanketed this interval with organic-rich calcareous shale (Shublik Formation) and shelf sandstone (Sag River Formation) across the tectonically stable northern platform. The overlying Jurassic section (Kingak Formation) consists of southward prograding marine clastics. The Sohio Nechelik #1 well was cored throughout the Ivishak Formation. The Ivishak is described as white, gray, clear quartz-rich sandstone, with minor amounts of chert, coal, pyrite, dolomite, calcite cement, and occasional mudstone pebbles. The sandstone is well consolidated, fine to medium grained, moderately sorted with thin conglomerate bands. Sedimentary structures include massive bedding, trough and planar crossbeds outlined by muddy and silty laminae, and some ripple cross-lamination. 5 e e Formation Nomenclature Age Formation Depositional Environment and Lithology Jurassic Triassic Triassic Kingak Sag River Shublik Marine shelf and prodelta shales Shallow marine sandstones Shallow to deep marine limestones, sandstone and shales Fluvio-deltaic sandstones, conglomerates, and siltstones, and shales Prodelta and shelf shales Permian Ivishak Permian Kavik Geology of the Waste Disposal Zones The geologic subdivisions for the confining and proposed injection zones are shown on the type log and the structural cross section. The Sohio Nechelik #1 log was used as the type log because of its proximity to the proposed development area and disposal well site. ARCO Fiord #1 is the next closest well that contains a suite of logs through the Permo- Triassic age strata. Kookpuk #1 is included on the regional cross section to illustrate the continuity of formations. The Bergschrund #1 well data is just in the process of being made public. The table below relates the injection and confining zones to the formations displayed in the exhibits. The stratigraphic nomenclature used here is the same as used in the Prudhoe Bay and Kuparuk Fields. It is also the same used by Jones and Speers, 1976. The formations described here are easily correlative to the fields to the east. Age Formation Injection and Confining Zones Jurassic Jurassic Triassic Triassic Permian Permian Upper Kingak Lower Kingak Sag River Shublik Ivishak Kavik Upper Confining Zone Upper Arresting Zone Upper Injection Zone Major Barrier Lower Injection Zone Lower Confining Zone Lower Confining Zone Permian Kavik Formation: Within the Colville River Unit area, the Kavik Formation is 200 to 250 feet thick and consists of a fairly uniform, medium to dark gray, silty shales which are pyritic, noncalcareous and micaeous. The Kavik Shale is interpreted to be 6 e e deposited as shelfal and pro-deltaic deposits. This section is easily correlatable and extends across the entire Alpine Unit and west to Kuparuk. Below the Kavik Shale are additional siltstones and shales of the Echooka Formation. This formation has very poor porosity and permeability and will probably act as an additional confining zone. The interbedded limestones and mudstones of the Lisburne Group occur beneath the Echooka Formation. Again, this formation has very poor porosity and permeability and could also act as an extension of the confining zone. Lower Proposed Injection Zone Permo-Triassic Ivishak Formation: Within the Colville River Unit, the Ivishak Formation is the predominant injection zone. The Ivishak is interpreted to be deposited as fluvial- deltaic sandstones. The gross interval thickness is 600 - 700 feet thick and consists of thick-bedded sandstones, thin-bedded conglomerates, and siltstones and mudstones. The sandstones are fine-medium grained, well consolidated, and have moderate reservoir quality. The siltstones and mudstones act as vertical barriers, of which two to three can be correlated between Nechelik #1 and Fiord #1 wells. Major Barrier Between Injection Zones Triassic Shublik Formation: Between the two proposed injection zones, there are 350 to 400 feet of shale, siltstones, and limestones deposited during a Triassic marine transgression. The base of the barrier or Lower Shublik Formation consists predominantly of siltstones and shale. This interval is extremely correlative and consistent in character and thickness. This section is overlain by the high resistivity limestones of the Upper Shublik Formation. These limestones are interpreted to have been deposited in a shallow marine environment during a period of quiescence with minimal clastic input. This horizon is also easy to correlate and very uniform in thickness. Porosity and permeability are poor. Upper Proposed Injection Zone Triassic Sag River Formation: The upper injection zone within the Colville River Unit is the Sag River Formation which contains approximately 50 feet of gross sand thickness. The Sag River sandstone consists of fine-grained, glauconitic sandstones interpreted as lower shoreface/shallow marine shelf deposits. The Sag River has good reservoir properties with an average permeability of 120 millidarcies. 7 e e Upper Arresting Zone Lower Jurassic Kingak Formation: The Lower Jurassic Kingak Formation occurs above the Sag River Formation up to the 13 log marker picked at the base of a resistivity bulge. The Lower Jurassic is 700-800 feet thick and consists predominately of shales. The shales are interpreted to be deposited as marine shelf and/or prodelta mudstones. This thick shale horizon is extremely consistent. Upper Confining Zone Upper Jurassic Kingak Formation; The arresting zone is overlain by 500 feet of the Upper Jurassic Kingak Formation, which comprises the upper confining zone. The Upper Kingak gradationally coarsens upwards into shales and thin siltstones. The interbedded shales and siltstones are interpreted to be deposited as marine shelf and/or prodelta mudstones. This thick sequence horizon is extremely consistent, has very poor horizontal and vertical permeability and therefore, represents a competent barrier to vertical fluid movement. Lithologv Above Upper confining Zone Above the confining zone is a 60-foot thick sandy interval that is the Nechelik tight oil zone and several hundred feet of shale that terminates at the base of the Alpine oil reservoir. With the exception of the Nechelik tight oil zone and the Alpine oil reservoir, no major developed sand intervals exist to the base of the permafrost. A few thin lenticular sands are present but they are not readily correlatable across the field area. Structure Structure maps for key horizons are included as Exhibits 7-9. These maps were generated from a 3D seismic grid that was tied into existing well data (Nechelik #1 and Fiord #1). The seismic covers this area with a square grid of data points every 28.5 feet. The lateral accuracy of this data set for locating faults is +/- 165 feet. The vertical accuracy of the depth maps is +/- 50 feet as tested by prior drilling results. The general structure of the stratigraphic sequence is dominated by dips of 1 to 2 degrees toward the southwest. Extensional northwest-trending faults that cut the Ivishak section generally have a throw that ranges from 20 to 50 feet and tend to die out within the overlying thick Jurassic shale section. These are normal faults as depicted on Exhibit 13. The dense shales should not have a rubble zone associated with their fault planes and thus are expected to be sealing, as evidenced by conditions at the main Prudhoe Bay fields. The contour map on the base-permafrost is shown in Exhibit 10. It was constructed using well log data and is picked by resistivity and sonic log measurements. The permafrost 8 e e ranges from 1200 feet to less than 700 feet in the Colville River Unit, thinning toward the west-southwest. Occurrence of H vdrocarbons There are no hydrocarbon accumulations within the Permo-Triassic proposed injection intervals in the Colville River Unit. Extremely faint residual oil shows are present in the Nechelik well. This is to be expected as these beds probably acted as migratory routes long ago for hydrocarbons that are now accumulated elsewhere. Wireline logs indicate that these zones are now wet. Outcrops and Recharge N one of the Permo-Triassic or Jurassic formations outcrop in the local area or intercept the 700 - 1200 foot thick permafrost zone. The injection zones occur 8000 feet below the permafrost. References Jones, H.P., and Speers, R.G., 1976, Permo-Triassic Reservoirs of Prudhoe Bay Field, North Slope, Alaska. AAPG Memoir 24. Tulsa, Oklahoma, pp. 23-50. 9 · e Well Logs 20 AAC 25.252 (c) 5 Well logs will be provided when the disposal well is drilled. Logs from existing exploratory and development wells have previously been provided to the Alaska Oil and Gas Commission. 10 it e Well Construction 20AAC 25.252 (c) 6 Wells will be drilled to the indicated bottom hole locations and to a final vertical depth of approximately 9,950 feet. The drilling program calls for maintaining accuracy that will allow hitting within 250 feet of the target. All construction requirements exceed the specifications required by the State of Alaska Oil and Gas Commission regulations. Construction details are included for well WD-2. The casing-cementing program for WD-2 is depicted schematically in the Exhibit 11. The surface hole will be logged as specified to ensure that the surface casing is well bonded to the formation below the permafrost. . The use of Class-G cement as tail slurry around the casing shoe will ensure good zonal isolation around the bottom of the casing. A full logging program will be run in the lower hole. The injection casing will be cemented with an excess volume to ensure the cement top is at +/- 6,600 feet TVD. Cement bond logs will verify zonal isolation. Both surface and injection casing integrity will be verified by pressure testing. The tubing by casing annulus will be isolated above the injection zone by a packer. A landing nipple to accept a wire line deployed downhole check valve will be installed in the tubing string below the permafrost. The annulus will be brine filled with a diesel cap for freeze protection. The tubing will be heat traced to provide heat should it be required during extended shut-in periods. Both the tubing and tubing by casing annulus will be pressure tested to 3500 psi. Should the pressure test fail the tubing will be removed and the problem corrected before the drilling rig leaves location. The wellhead assembly is shown in Exhibit 12. The wellhead, controls, and monitoring instrumentation will be enclosed in an insulated and heated well house. Flow lines to the well will be heat traced and insulated. 11 · e Proposed Drillin2 and Completion Program: Well WD-2 Surface location: ASP "X" 386,665 and ASP "Y" 5,976,560 444' FSL & 2052' FEL See 32, TI1N R5 E ASP "X" 388,230 and ASP "Y" 5,976,240 149' FSL & 482' FEL See 32, T12N R5E 250 ft Radius (+/- 250 feet) Target location: Target Accuracy Estimated start date : 1st Qtr 1999 Maximum angle: Kick off depth : 18 degrees 3000 feet Wellbore azimuth: Kelly bushing (KB) elevation: 104.5° 57 ft AMSL Item and Depths Subsea TVD (*BKB) MD (*BKB) (*below kelly bushing @ rig floor) 16" Conductor ±60 ±117 +/-117 Base Permafrost 800 857 858 9 5/8 Casing Shoe 2726 2783 2800 Top Confining Zone (U. Kingak) 7360 7417 7646 Base Arresting Zone (L. Kingak) 8640 8697 8995 (Top Injection Zone - Sag River) Lower Injection Zone (Ivishak) 9105 9162 9485 Top Lower Confining Zone (Kavik) 9750 9807 10164 Well Total Depth 9900 9957 10322 (7 Inch Casing Shoe) 12 e e L02gin2 Pro2ram Open Hole: 12 1/4 Surface Hole: GR/RES/NEUT/DENS (TD to Surface) 8 1/2 Hole: GR/RES/NEUT/DENS (TD to 9 5/8 shoe) Cased Hole: Cement bond log from 9 5/8 shoe up to Surface (consistent with EP A request for Class I disposal). Cement bond log from total depth to top of cement. MWD survey while drilling. Freeze Protection Plan The 4 ~ X 7 inch tubing annulus will be freeze protected with diesel from the surface down to the base of the permafrost. This interval will also be heat traced. Casing I Tubin2 Specifications Csg/Tbg Tension Burst Collapse ~ OD WtlFt Grade Conn. k lb. ~ ~ Conductor 16" 62# H-40 WLD N/A NIA N/A Surface 9 5/8" 36# J-55 BTC 564 3520 2020 Production 7-5/8 29.7# L-80 STL-FJ 683 6890 4790 Production 7" 26# L-80 BTC 604 7240 5410 Tubing 4 Yz" 12.6# L-80 STL-FJ 191 8440 7500 Tubing 4 Yz" 12.6# L-80 BTC-Mod 209 8440 7500 13 Cement Volumes 9-5/8 Inch Surface Casing: Measured Depth: Basis: Total Cement Vol.: Lead Slurry Vol.: Tail Slurry Vol.: 7 Inch Injection Casing: Measured Depth: Basis: Total Cement Vol: . e 2,800 feet 300% annular volume excess over permafrost 50% annular volume excess sub-permafrost 80 foot shoe track (12-1/4 x 9-5/8" annulus) 1,965 (cu ft) - subject to revision 1,789 (cu ft) +/-410 sx Arctic Set 3 Lite at 4.47 cu ft/sx (from surface to 300 feet MD above section TD) 176 (cu ft) +/-150 sx Class G cement at 1.17 cu ft/sx (last 300 feet of annulus to section TD) 10,322 feet 500 feet MD above top Alpine, with 30% excess. (8-112" x 7" annulus) 608 cu ft, +/-540 sx at 1.16 cu ft/sx. (subject to revision based on hole conditions) Construction Procedures 1. Set and cement 16 inch conductor casing. Move in drilling rig. Install diverter and function test. 2. Drill 12 1/4 inch hole to the surface casing point. Rig up and run electric line logs. Run and cement 9 5/8 surface casing. Install the wellhead and blow-out pre venter (BOP) and pressure test per AOGCC regulations. 3. Run cement bond log from landing collar to surface at this time or wait until open hole logs are run. 4. Test casing to 2,500 psi for 30 minutes. 5. Drill 8 1/2 hole through the proposed injection interval to total depth (TD). Rig up and run E-line logs, and cement bond log if not run in step 3. 6. Run 7 x 7-5/8" inch casing to TD. Cement casing string as per program. 14 . . 7. Displace wellbore to clean seawater. 8. Run a cement bond log from TD to the top of cement (TOC). 9. Run 4~, 12.6 #, L-80 tubing with heat trace wiring and down hole check valve nipple at +/- 1,300 feet. Freeze protect annulus with diesel. Test tubing and tubing-casing annulus separately to 3,500 psi. 10. Install the wellhead and test to 5000 psi. Release drilling rig. 11. The drilling fluid program and surface control system will conform to the regulations set forth in the AOGCC Regulations - 20 AAC 25.033. 15 . . Waste Sources and Characteristics 20 AAC 25.252 (c) 7 Class II disposal wells are defined as wells which inject wastes brought to the surface in connection with oil and gas production, with natural gas or liquid hydrocarbon storage operations. Class II fluids may be 1pixed with other wastes from plant operations; unless those wastes are classified as hazardous waste under 40 CFR 261.3. . Typical RCRA exempt wastes which are acceptable for injection can include the following: Drill Cuttings, Drilling fluids, Cement fluids, Completion fluids W orkover fluids, Stimulation fluids, Frac Sand, Produced Water, Crude Oil, Production Vessel Sludge/Sand, Fresh or Sea Wat~r, Natural Gas Liquids, Rig Wash, Well Cellar Fluids, and others allowed under 40 CFR 261.4. Tvpical Injection Stream Calculations indicate that the Sag River and Ivishak formations can not be fractured sufficiently to dispose of a large volume of solid material. There is concern that screen- out or plugging will render a well or disposal interval useless. Therefore the disposal of drilling mud and cuttings is not envisioned for these wells. On occasion, some mud will probably have to be directed to them b~~cuttin~s!!?.!E:.a.: g~i~~LI2lant ~o~,~<!~~_l'J:!y.~o/ there on an emergency basis. Other exempt solids will also be directed elsewhere ..-........-."............",._.........,~, ....~......_._...r··--'~-,·-~,_·,·~-,----_.Lk whenever possible. Exempt wastes routinely generated by well workovers, contaminated crude oil, vessel sludge/sand, diesel/methanol usage, spent acid, fracturing operations, snow melt, and plant upsets could total 4 million barrels. Produced water disposal could be expected to 16 ~ X'<I (¡IT' ~ ). J/ ~ ~ 9\ .~\ -~ "b-\ .. .r ~ e e total 14 million barrels before the rate reaches 10,000 BPD. When the field rate approaches this level, water-polishing equipment will be installed to allow reinjection into the oil reservoir. Over a 20-year project life, produced water would constitute about 80 percent of the waste stream. Other exempt waste activities would account for the rest. Injection Rates After plant startup, but prior to significant produced water breakthrough, the injection rate will range up to 300 BPD. Produced water breakthrough from waterflood or EOR operations is projected to occur about year five and build toward 10,000 BPD by year fourteen. If this projection is accurate, the disposal rate will reach 330,000-360,000 barrels per month in this time frame. At some point before the 10,000 BPD rate is reached, it will be advantageous to start reinjection into the oil reservoir. The disposal rate would then drop back to the 300-500 BPD range. 17 .., e e Injection Pressure 20 AAC 25.252 (c) 8 \ The following table shows the range of injection pressures that are estimated to occur through the life of a single well over many years. They reflect behavior of the tighter Ivishak formation since the Sag River is clean sand with significantly better porosity and permeability. The Ivishak sand intervals containing clay, are tightly cemented, and are interspersed with enough shale stringers that it will be hard to push dirty fluids into a completion interval for' a long period. The smaller pore throats will progressively become plugged in the region around the wellbore. This damage zone will restrict well injectivity so that in order to maintain the required disposal rate, it will be necessary to stimulate or fracture past the restriction. It is anticipated that near-wellbore fractures will be required to establish new flow paths to undamaged rock. The projected pressures reflect what is expected to occur because of variations in lithology and changes in the well injectivity index with time. Should use of the Sag River formation be required, fracturing would be much less prevalent. Further discussion on fracturing is included in the next section. Surface Injection Pressure Early time frame: No fracturing ofthe injection zone required but assuming zones are originally slightly over pressured. 1700 psi Several years into field life: Some fracturing of the near wellbore region may occur to get past early plugging caused by dirty fluids. Assumes a clean sand fracture gradient of 0.65 psi/foot. 2200 psi Later in field life: Fracturing of the near wellbore region is required. Assuming a tighter shaley/sand fracture gradient of 0.70 psi/foot and a higher injection rate, this level of pressure is required to over come estimated fracture mechanics and tubing frictional losses. 3000 psi Maximum injection pressure: This generates a static fracture gradient ranging from 0.77 - 0.80 psi/ft. If friction losses are taken into account these gradient values would be smaller. 3200 psi. 18 e e Waste Confinement 20 AAC 25.252 (c) 9 The following discussion focuses on the possibility of failure to keep injected waste confined to the subsurface strata located below the upper confining zone. The purpose of the assessment is to provide discussion on potential problems, how these problems will be avoided, and how they will be handled in the unlikely event that they occur. Risks of interest that must be considered are as follows. Uncemented Wellbores and Wellbore ChanneliDl! No oil reservoir development wells will penetrate the upper confining zone. Development wells will be drilled from two gravel pads and will reach a depth 400 - 500 feet above the top of the upper confining zone. Production well long casings will be cemented across the oil reservoir and 500-1000 feet into the shale that lies above it. There is no confinement risk associated with wellbore leakage due to development wells. The only leakage that could occur would be associated with channeling adjacent to an injection well. This would be detected by channel logs and would be repaired by squeeze cementing. Verification of the repair by pressure testing and logging would follow. Natural FaultinS! As shown on the structure maps and on Exhibit 13 there are normal faults cutting the injection and arresting zones in the local area. They are all minor compared to the thickness of the over lying Kingak shale. At this depth sand intervals will generally produce a rubble zone that can permit flow along the fault plane; however, the brittle shales typically do not follow this pattern. Experience has shown that it would take a very large pressure differential to create flow along a normal fault where dense shales are juxtaposed against each other. At Prudhoe Bay, major faults extend from the main oil/gas reservoirs at +/- 8500 feet to the Cretaceous water disposal zone at +/- 6000 feet. With a large gas cap present in the Ivishak, obviously there was no upward gas migration or the Kingak shale would not have become the cap rock for hydrocarbon accumulations. By the end of 1996, the main oil reservoir pressure had declined 1000 psi. Conversely, the over lying Cretaceous aquifers have been over-pressured several hundred psi due to a billion barrels of produced water disposal. This imbalance creates a pressure gradient of over 0.4 psi/ft (1000 psi/2500 feet). No flow has been detected from the Cretaceous zone. 19 e e Pressure buildup calculations indicate that the fault nearest the first disposal well might see a 100 psi pressure rise. If the 0.4 psi/ft gradient were a limiting, worst-case leakage condition, then a 250 foot thick arresting zone would contain any potential upward migration. These faults will not permit migration into the confining zone. No confinement risk can be anticipated due to their presence. Fracturin2 of the Upper Confining Zone Wellbore damage is expected to accumulate from the periodic disposal of dirty fluids. This will necessitate wellbore stimulations and possibly near-wellbore fracturing to get past the damage zone and maintain the required disposal rate. The fractures should not be extensive since fluid leak off will be high once new rock is contacted. Because of the lithology contrasts, lateral fracture growth would be expected to be greater than what occurs in the vertical dimension. If the shales fracture at a gradient of 0.80 psi/ft and clean sands at 0.65, the stress contrast becomes 0.15 psi/ft. At an arresting zone base of 8,650 feet, this generates a stress contrast of 1297 psi. This indicates that should the Sag River Formation be perforated, and a fracture developed, it could not be expected to penetrate the overlying Kingak. shale. As an effective buffer, if there were some vertical growth above the Sag River, it would never penetrate the 660 feet of arresting zone and reach the confining zone. Confinement risk associated with fracturing is almost non-existent. Comparison With Similar Projects There are similar but no direct comparisons with other North Slope disposal projects because dirty water/wastes are not injected into these formations on a long-term basis. However, since 1985, produced water and seawater injected into 206 Prudhoe Bay Sag River and Ivishak wells has totaled 6.146 billion barrels. At the Endicott field, 506 million barrels has gone into 26 wells and at the new Pt. McIntyre field, 205 million has gone into 13 wells. The average per well ranges from 30 MMB at Prudhoe to 16 MMB at Pt. McIntyre. Many of the above wells have minor fracture systems associated with their injection zone, some caused by thermal fracturing due to injection of cold surface waters and others by fracturing past well bore damage zones. Some of the fractures are permanent and others probably open and close. In the rare case where injected fluids are not confined to the desired sub-interval, it is usually associated with a poor casing cement job. Fluids are all confined to the Ivishak gross section. 20 e e Summary The risk of non-confinement of injected wastes must be viewed as minimal to non- existent. A competent upper arresting-confining zone and successful large scale water injection at other locations, coupled with proper well monitoring, all indicate wastes can be confined and no environmental damage result. 21 . e Formation Water Salinity 20 AAC 25.252 (c) 10 Salinity Calculations In the Alpine project area only the Nechelik #1 well has been logged from surface through the injection zone. No clean sands were encountered above the confining zone; however, the Alpine #1 well did cut some thin Albian sands at 5150-5204 feet and Bergschrund #1 found a thin shelf sand at 4220 feet. Salinity calculations made on available intervals resulted in the following. · Bergschrund #1 (4220 feet) 15,000 ppm NaCl eq. · Alpine #1 (5150-5204 feet) 15,000 ppm NaCl eq. · Nechelik #1 (Sag River Formation) 18,000 ppm NaCl eq. · Nechelik #1 (Ivishak Formation) 17,000 ppm NaCI eq. The methodology used and results obtained from salinity calculations on the AlbianlNanushuk Shelf sand stringers (Alpine #1 and Bergschrund #1), Sag River, and Ivishak Formations (Nechelik #1 well) are as follows. The calculations use the standard Archie correlation and log derived data to obtain an Rwa value using the following formula: Rwa = (porosity) m (Rt) / a ........... with the following definitions: Rwa Porosity Rt m a Resistivity of water necessary to make a zone 100 % wet Porosity in decimal from logs Formation resistivity from logs Cementation exponent Assumed to be 1.0 per the Archie correlation The cementation exponent is the variable of least certainty. The best source for determining this value is from special core analysis (SCAL) when available. No SCAL is available for the Albian interval; however, such data does exist for analogous fine to very fine grain sand in the area. This data has yielded: 22 e e Alpine section SCAL from the Alpine #1 well Sag River SCAL as documented in ARCO TSR 95-46, internal report m = 1.55 m = 1.6 The following exponents will be used in these salinity calculations. Shallow intervals (4000- 5000 feet) Sag River Formation Ivishak Formation m = 1.6 m = 1.7 m = 1.8 · Nanushuk Shelf Sand: (Bergschrund #1 well depth 4220 feet) This shelf sand is evident in two wells at approximately 4200 feet subsea. Rt = 4.0, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The calculation yields an Rwa equal to 0.356. Using Schlumberger Chart Gen-9 and a formation temperature of 80 degrees F, gives a salinity of 15,000 ppm NaCI equivalent. · Albian Interval: (Alpine #1 well depth 5150-5204 feet) There is a collection of thin sands in this well and a complete set of logs is available. Rt is taken from the shallow MWD tool because of minimum exposure time to invasion and superior vertical resolution in three foot thick beds. Porosity comes from the density log. Rt = 3.2, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The Calculation yields an Rwa equal to 0.293. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100 degrees F, gives a salinity of 15,000 ppm NaCl equivalent. · Sag River Formation: (Nechelik #1 well depth 8432-8480 feet) This is a thick, clean, uniform sand interval with a complete set of logs. Rt = 1.9, Raw density = 2.32, m = 1.7, Porosity = (2.65-2.32) / (2.65-1.0) = 0.20 The calculation yields an Rwa of 0.145 and with a formation temperature of 165 degrees F, produces a salinity value of 18,000 ppm NaCI equivalent. 23 e e · Ivishak Formation: (Nechelik #1 well depth 9420-9460 feet) This lower sand member has the lowest resistivity and greatest SP excursion. Rt = 3.3, Raw density = 2.35, m = 1.8, Porosity = (2.65-2.35) / (2.65-1.0) = 0.18 The calculated Rwa equals 0.15 and with a formation temperature of 185 degrees F, a salinity of 17,000 ppm N aCI equivalent is obtained from the Schlumberger chart. Water Sample Analvses The following water samples were obtained from drill stem and production tests in the general Colville Delta area. · Colville #1 well 7922 feet · 14 miles Northeast · 22,485 mg/l TDS (tested) Shublik Formation · Colville #1 well 9073 feet · 14 miles Northeast · 24,004 mg/l TDS (tested) Lisburne Formation · Kalubik #1 well 5050-5250 feet Albian Interval · 17 miles Northeast · Flowed 151 barrels to surface · 24,300 mg/l TDS (average of tests) · Kalubik Cr. #1 well 9047-9188 Lisburne Formation · 21 miles East · Flowed 325 barrels of water · 21,847 mg/l TDS (tested) · Mukluk well 7490-7520 Ivishak Formation · 23 miles North · Flowed 984 barrels of water · 11,000 ppm chloride tested · 18,150 mg/l TDS (calculated) 24 e e · Mukluk well 8145-9860 Lisburne Formation · 23 miles North · Flowed 1750 barrels of water · 11,000 ppm chloride tested · 18,500 mg/l TDS (calculated) Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Permit Application, Appendix D, previously submitted to the Commission in September 1997. 25 e e Aquifer Exemption 20 AAC 25.252 (c) 11 Aquifer Exemption No underground sources of drinking water (USDW) have been identified within the Colville River Unit area. Since there are no USDW's at Alpine, an aquifer exemption is not applicable. The Colville River Unit Area includes; Township I1N Range 4E - (Umiat Meridian) Sections 1-5 all, 7-16 all, 21-27 all. Township 11N Range 5E - (Umiat Meridian) Sections 1-24 all, 29-30 all. Township 12N Range 3E - (Umiat Meridian) Sections 25-27 all, 34-36 all. Township 12N Range 4E - (Umiat Meridian) Sections 20-21 all, 22 excluding portion in Survey USS 9502 (2), 23-27 all, 28-32 excluding portions offshore, 33-36 all. Township 12N Range 5E - (Umiat Meridian) Sections 1-36 all. Township 13N Range 5E - (Umiat Meridian) Sections 9-10 all, 15-22 all, 26-36 all. North Slope Resident Water Supplies The Alaska North Slope is populated by approximately 6,200 permanent residents in eight communities. Because surface water is plentiful, seven of the eight native villages on the North Slope rely on surface water from lakes or lagoons for their water supply. The closest permanent resident population at the village of Nuiqsut (population 450) is approximately 9 miles from the Alpine project area. In the North Slope area, only the village of Anaktuvuk Pass (population 325), approximately 170 miles south of Alpine in the Endicott Mountains, has a subsurface well for their public water supply. A table of North Slope demographics for permanent residents and their potable water sources is attached. 26 e e Approximately 3,000 industry workers temporarily reside on the North Slope in one of six major camps. The transient populations residing at operator and contractor run camps for the North Slope oil fields all rely on surface water for their water supply. Even the base camp at Endicott's offshore facility treats seawater for its drinking water supply rather than uses a subsurface source. A tabulation of these potable drinking water systems and their operating costs is attached. The Alpine facility will also use surface water as its potable source. 27 - e Potable Water Sources and Demographics Villages of the North Slope (October 1994) Distance PWS ** Potable from LD. Water Village Population Alpine Number Source (Miles) Barrow 3404 150 620078 Isatkook Lagoon Wainwright 570 210 620086 Freshwater Lake Kaktovik 280 170 620248 Freshwater Lake Pt. Hope 711 350 620426 Freshwater Lake Nuiqsut 450 9 620264 Freshwater Lake Atqasak 220 160 620094 Surface Lake Pt. Lay 150 290 N/A Surface Lake Anaktuvuk Pass 325 170 650057 70 Foot Well ** Public Water Supply Identification Number 28 e e Potable Water Systems North Slope Oil Field Area (October 1994) Oil Field Camps Approximate Population Potable Water Source System Size (gal/day) Operating & Maintenance Cost (¢/gal) BPX 800 * Lake 102,000 3 Prudhoe Bay Base Operation Center ARCO 1100 * River 176,000 1.0 Prudhoe Bay Base Operation Center ARCO 350 * Lake 76,000 2.1 Kuparuk River Base Operation Center Milne Point 150 * Lake 30,000 1-3 Central Facility Endicott 120 Seawater 20,000 1.5 Base Operation Center Kuparuk 130 River 24,000 1.5 Industrial Center Pump Station 1 50 Purchased N/A N/A Deadhorse 320 River 50,000 1.5-2.0 Service Area . Potable water also hauled to temporary drilling rig camps. 29 e e Mechanical Integrity 20 ACC 25.252 (d) (e) Mechanical integrity will be verified after well construction by testing to 3500 psi as outlined earlier in part 25.252 (c) 6. This will conform to 20 AAC 25.412. The casing- tubing annulus pressure will be monitored regularly and reported to the Commission on Injection Report Form 10-406. The tubing-casing annulus volume will vary, and the annulus fluid itself will expand and contract due to temperature changes. At the present time it is hard to specify exactly what high-low annulus pressure limits should be established to trigger a warning and possible shutdown. The exact points will need to be established once a repeatable pattern of fluctuation has been established. This can be determined after several months of performance that would include both the summer and winter ambient temperature swings, which affect this operation. Channel logging to verify fluid confinement will be performed as dictated by operating events. Reservoir pressure testing will be performed as needed. 30 e e Wells Within Radius of Investieation 20 ACC 25.252 (h) Bergschrund #1 and development well CD 1-22 are the only wells within 1/4 mile of the disposal area. Bergschrund #1 does not penetrate the injection or arresting zones but does touch the top of the confining zone. It's completion report and abandonment schematic is attached. Well CDl-22 does not penetrate the confining zone. No corrective action plans are required. 31 . . Alpine Area Injection Order Attachment 15 20 AAC 25.402 (c)(3) Affidavit of Michael D. Erwin Regarding Notice of Surface Owners Michael D. Erwin, on oath, deposes and says: 1. I am the Alpine Coordinator at ARCO Alaska, Inc., the designated operator of the Colville River Unit (which will include the Alpine Oil Pool). 2. On November 10, 1998, I caused copies of the Area Injection Order Application to be provided to the surface owner and operator of all land within a quarter mile of the unit as listed below: Mr. Kenneth A. Boyd, Director Alaska Department of Natural Resources Division of Oil & Gas 3601 C Street, Suite 1380 Anchorage, Alaska 99503-5948 Mr. Joe Nukapigak, President Kuukpik Corporation PO Box 187 Nuiqsut, Alaska 99789-0187 ARCO Alaska, Inc. Attention: Mark Ireland ANO- P.O. Box 100360 Anchorage, Alaska 99510-0360 /1J1A. ¡'\:\ ~ \ . f i vv~ku.V !/ (~~. ... Michael D. Erwin STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) Subscribed and sworn before me this 2nd day of December, 1998, by Michael D. Erwin. \\l([{{{(((f \\\ ~ E H í/ \.\ ð--{ . . . : ·.oC,""// ~~~. ~h .....,!'-;.. ~ J.::...~ t~ .....,.Å_-:.=. '-..... ,.,.,('\'1 ~ ......;'. !" '",,'" ..- .:::....: h "'-"'"""'-. '~~~= = *" PLiFfi \(, : ..., -.. .. ",~.jI\:...~ ~~fl.,,~-~ Notary Publiá\n and for Alaska My Commission Expires: 8/15/2001 ..... ..... . ~t.C'.. " ~~7":.."'" ./..1. ./ .I./j l ARCO Alaska, Inc. a Post Office B~00360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 e, ~~ ~, November 1, 1998 Commis·¡joner David Johnston Ala8ka Oil and Gas Conservation Commission 300] Porcupine Drive Anchorage, Alaska 99501 Subject: Application for Disposal Injection Order Colville River Unit, North Slope Basin Dear Mr.. Johnston: ARca Alaska, Inc. submits for your review and action, this application for a disposal injection order to authorize injection of RCRA exempt drilling and production wastes into strata within the unit boundary. The application was prepared in accordance with Title 20, Chapter 25.252. As discussed with Mr. Blair Wondzell and Ms. Wendy Mahan, a Class n disposal injection order might provide a needed contingency for the Alpine project in the unlikely event the EP A does not issue a Class I well permit prior to c0mmencement of drilling operations. Development drilling is expected to begin in early 1999 with a disposal well. A ruling is requested that will allow for appropriate planning and other activities to occur before that time. An injection interval bounded by major shales has been identified between 8,640' - 9,750' TVDss. At this time it is not envisioned that drill cuttings or large volumes of mud will be directed to these Sag River and Ivishak formations. The injection stream wíll mostly consist of produced water from the oil reservoir. Lesser volumes of dirty fluids from drilling and production operations will have a low solids content. Inquiries regarding clarification may be directed to either Mike Stahl or Doug Chester at this office. ('~ RECEIVED r:0V'~ 199a Alaska Oil & Gas Cons. Commission Anchorage Rr Mar M. Ireland Alpine Development Manager ARca Aiaska, a Subsidiary · - Application for DIO November 1, 1998 Page 2 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 Jonathan Williams Us EPA, Region 10 Groundwater Protection Unit 1200 Sixth Avenue (OW-137) Seattle, WA 98101 (letter only) 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 REC£\\J£D \~,OV -,-4 "\9S8 f' miSsion I,,, 0\\ & Gas Cons. vom Ala,S1\Co\ Anchorage · ,8 Application For Disposal Injection Order Alpine Development Project Colville River Unit North Slope Basin 20 ACC 25.252 November 1998 ''','''. '~'J';"~ ~ .......~-~ 20 AAC 25.252 (c) 1 (c) 2 & 3 (c) 4 (c) 5 (c) 6 (c) 7 (c) 8 (c) 9 (c) 10 (c) 11 (d) & (e) (h) Exhibits 1 2 3 4 5 6 7 8 9 10 11 12 13 14 . - Table of Contents Well Locations Surface Owners and Operators Geologic Details Well Logs Well Construction Waste Sources and Characteristics Injection Pressure Waste Confinement Formation Water Salinity Aquifer Exemption Request Mechanical Integrity Wells Within Radius of Investigation Page 3 4 5 10 11 16 18 19 22 26 30 31 Alpine Project Area Surface Facilities Spider Map - Proposed Well Courses Type Log - Nechelik #1 Geologic Cross-section Seismic Section Structure Map - Top Confining Zone Structure Map - Top Injection Zone Structure Map - Lisburne Formation Base of Permafrost Well Schematic Well Head Schematic Well WD-2 Fault Picture Aquifer Exemption Area 2 .',< · ,e Well Locations 20 AAC 25.252 (c) 1 Exhibits 1 and 2 show the proposed unit boundary and the surface facilities that will be located in the Colville River delta. Exhibit 3 is a spider map showing the proposed development plan for the central facilities pad. Field development will require 92 wells with approximately 46 drilled from this pad. Surface casings of the development wells will be set below the West Sak formation at approximately 2400 feet. The first well to be drilled will be disposal well WD- 2. It will be directed in an east -southeasterly direction as shown. The spider map shows three disposal wells; WD-1 at an azimuth of 69 degrees, WD-2 at 104 degrees, and WD-3 at 322 degrees. WD-1 may be drilled as a backup, but it is not anticipated that WD-3 will be drilled unless reservoir or well mechanical problems impact the utility of the first two. The only existing wells near the disposal area are exploratory well Bergschrund 1 and development well CDl-22. Neither well reaches the top of the disposal interval, which is at approximately 8640 feet, subsea. 3 "", .....,..~ ,.", ... · e Surface Owners and Operators 20 AAC 25.252 (c) 2&3 The State of Alaska is the only surface owner within 1/4 mile of the disposal wells. No other operators are in the development area; therefore, no copies of the application need to be distributed other than to the state Department of Natural resources. The State of Alaska John Shivley, Commissioner State of Alaska, Department of Natural Resources 400 Willoghby Avenue, 5th Floor Juneau, Alaska 99801-1796 Three land owners near the unit boundary are several miles away. They are: Kuukpik Corporation Joe Nukapigak., President P.O. Box 187 Nuiqsut, Alaska 99789-0187 Lydia Woods Sovalik P.O. Box 75 Nuiqsut, Alaska 99789 Bureau of Land Management Thomas J. Allen, Director, Alaska State Office 222 W. 7th Avenue #13 Anchorage, Alaska 99513-7599 4 ............"."'"'.-:--'-- ~"""~."" ~~,-. · e Geologic Details Type Log, Cross Section, Structure and Stratigraphy 20 AAC 25.252 (c) 4 Introduction The geology of Permo-Triassic and Jurassic age sediments within the Alpine Unit area is described with specific reference to the proposed injection and confining intervals. Horizons and formations have been correlated westward from the Prudhoe Bay and Kuparuk Fields. Nomenclature from both the fields is applicable for the Alpine area. The horizons/formations can be correlated regionally and are shown on the type log and regional cross-section (Exhibits 4 and 5). The intervals of interest comprise clastic rocks of the Kavik, Ivishak, Shublik, Sag River, and Kingak Formations, in ascending order. A seismic section is presented as Exhibit 6. Structure maps on key horizons are presented in Exhibits 7-9 with the locations of the disposal wells noted. The Jurassic and Permo-Triassic sediments comprise the Ellesmerian sequence characterized by marine transgressive-regressive cycles deposited on a slowly-subsiding passive-margin ramp to the south with a broad, stable platform to the north. The Permo- Triassic Ivishak formation consists of lowstand fluvial-deltaic-marginal marine deposits that accumulated along the south-facing Ellesmerian ramp. Triassic transgression blanketed this interval with organic-rich calcareous shale (Shublik Formation) and shelf sandstone (Sag River Formation) across the tectonically stable northern platform. The overlying Jurassic section (Kingak Formation) consists of southward prograding marine clastics. The Sohio Nechelik #1 well was cored throughout the Ivishak Formation. The Ivishak is described as white, gray, clear quartz-rich sandstone, with minor amounts of chert, coal, pyrite, dolomite, calcite cement, and occasional mudstone pebbles. The sandstone is well consolidated, fine to medium grained, moderately sorted with thin conglomerate bands. Sedimentary structures include massive bedding, trough and planar crossbeds outlined by muddy and silty laminae, and some ripple cross-lamination. 5 ~~_.-~,-~... .... -- ~ e e Formation Nomenclature Age Formation Depositional Environment and Lithology Permian Kavik Marine shelf and prodelta shales Shallow marine sandstones Shallow to deep marine limestones, sandstone and shales Fluvio-deltaic sandstones, conglomerates, and siltstones, and shales Prodelta and shelf shales Jurassic Triassic Triassic Kingak Sag River Shublik Permian Ivishak Geolo2V of the Waste Disposal Zones The geologic subdivisions for the confining and proposed injection zones are shown on the type log and the structural cross section. The Sohio Nechelik #1 log was used as the type log because of its proximity to the proposed development area and disposal well site. ARCO Fiord #1 is the next closest well that contains a suite of logs through the Permo- Triassic age strata. Kookpuk #1 is included on the regional cross section to illustrate the continuity of formations. The Bergschrund #1 well data is just in the process of being made public. The table below relates the injection and confining zones to the formations displayed in the exhibits. The stratigraphic nomenclature used here is the same as used in the Prudhoe Bay and Kuparuk Fields. It is also the same used by Jones and Speers, 1976. The formations described here are easily correlative to the fields to the east. Age Formation Injection and Confining Zones Jurassic Jurassic Triassic Triassic Permian Permian Upper Kingak Lower Kingak Sag River Shublik Ivishak Kavik Upper Confining Zone Upper Arresting Zone Upper Injection Zone Major Barrier Lower Injection Zone Lower Confining Zone Lower Confining Zone Permian Kavik Formation: Within the Alpine Unit area, the Kavik Formation is 200 to 250 feet thick and consists of a fairly uniform, medium to dark gray, silty shales which are pyritic, noncalcareous and micaeous. The Kavik Shale is interpreted to be deposited 6 · e as shelfal and pro-deltaic deposits. This section is easily correlatable and extends across the entire Alpine Unit and west to Kuparuk. Below the Kavik Shale are additional siltstones and shales of the Echooka Formation. This formation has very poor porosity and permeability and will probably act as an additional confining zone. The interbedded limestones and mudstones of the Lisburne Group occur beneath the Echooka Formation. Again, this formation has very poor porosity and permeability and could also act as an extension of the confining zone. Lower Proposed Injection Zone Permo-Triassic Ivishak Formation: Within the Alpine Unit, the Ivishak Formation is the predominant injection zone. The Ivishak is interpreted to be deposited as fluvial-deltaic sandstones. The gross interval thickness is 600 - 700 feet thick and consists of thick- bedded sandstones, thin-bedded conglomerates, and siltstones and mudstones. The sandstones are fine-medium grained, well consolidated, and have moderate reservoir quality. The siltstones and mudstones act as vertical barriers, of which two to three can be correlated between Nechelik #1 and Fiord #1 wells. Ma.ior Barrier Between Injection Zones Triassic Shublik Formation: Between the two proposed injection zones, there are 350 to 400 feet of shale, siltstones, and limestones deposited during a Triassic marine transgression. The base of the barrier or Lower Shublik Formation consists predominantly of siltstones and shale. This interval is extremely correlative and consistent in character and thickness. This section is overlain by the high resistivity limestones of the Upper Shublik Formation. These limestones are interpreted to have been deposited in a shallow marine environment during a period of quiescence with minimal clastic input. This horizon is also easy to correlate and very uniform in thickness. Porosity and permeability are poor. Upper Proposed Injection Zone Triassic Sag River Formation: The upper injection zone within the Alpine Unit is the Sag River Formation which contains approximately 50 feet of gross sand thickness. The Sag River sandstone consists of fine-grained, glauconitic sandstones interpreted as lower shoreface/shallow marine shelf deposits. The Sag River has good reservoir properties with an average permeability of 120 millidarcies. 7 e e Upper Arresting Zone Lower Jurassic Kingak Formation: The Lower Jurassic Kingak Formation occurs above the Sag River Formation up to the 13 log marker picked at the base of a resistivity bulge. The Lower Jurassic is 700-800 feet thick and consists predominately of shales. The shales are interpreted to be deposited as marine shelf and/or prodelta mudstones. This thick shale horizon is extremely consistent. Upper Confining Zone Upper Jurassic Kingak Formation: The arresting zone is overlain by 500 feet of the Upper Jurassic Kingak Formation, which comprises the upper confining zone. The Upper Kingak gradationally coarsens upwards into shales and thin siltstones. The interbedded shales and siltstones are interpreted to be deposited as marine shelf and/or prodelta mudstones. This thick sequence horizon is extremely consistent, has very poor horizontal and vertical permeability and therefore, represents a competent barrier to vertical fluid movement. Lithology Above Upper confining Zone Above the confining zone is a 60-foot thick sandy interval that is the Neche1ik tight oil zone and several hundred feet of shale that terminates at the base of the Alpine oil reservoir. With the exception of the Nechelik tight oil zone and the Alpine oil reservoir, no major developed sand intervals exist to the base of the permafrost. A few thin lenticular sands are present but they are not readily correlatable across the field area. Structure Structure maps for key horizons are included as Exhibits 7-9. These maps were generated from a 3D seismic grid that was tied into existing well data (Nechelik #1 and Fiord #1). The seismic covers this area with a square grid of data points every 28.5 feet. The lateral accuracy of this data set for locating faults is +/- 165 feet. The vertical accuracy of the depth maps is +/- 50 feet as tested by prior drilling results. The general structure of the stratigraphic sequence is dominated by dips of 1 to 2 degrees toward the southwest. Extensional northwest-trending faults that cut the Ivishak section generally have a throw that ranges from 20 to 50 feet and tend to die out within the overlying thick Jurassic shale section. These are normal faults as depicted on Exhibit 13. The dense shales should not have a rubble zone associated with their fault planes and thus are expected to be sealing, as evidenced by conditions at the main Prudhoe Bay fields. The contour map on the base-permafrost is shown in Exhibit 10. It was constructed using well log data and is picked by resistivity and sonic log measurements. The permafrost 8 e e ranges from 1200 feet to less than 700 feet in the Alpine Unit, thinning toward the west- southwest. Occurrence of Hvdrocarbons There are no hydrocarbon accumulations within the Permo-Triassic proposed injection intervals in the Alpine Unit. Extremely faint residual oil shows are present in the Nechelik well. This is to be expected as these beds probably acted as migratory routes long ago for hydrocarbons that are now accumulated elsewhere. Wireline logs indicate that these zones are now wet. Outcrops and Recharge None of the Permo-Triassic or Jurassic formations outcrop in the local area or intercept the 700 - 1200 foot thick permafrost zone. The injection zones occur 8000 feet below the permafrost. References Jones, H.P., and Speers, R.G., 1976, Permo-Triassic Reservoirs of Prudhoe Bay Field, North Slope, Alaska. AAPG Memoir 24. Tulsa, Oklahoma, pp. 23-50. 9 _...~c-~_.. ~. -'·~.l~""t·."..^~·"""".<", e e Well Logs 20 AAC 25.252 (c) 5 Well logs will be provided when the disposal well is drilled. Logs from existing exploratory and development wells have previously been provided to the Alaska Oil and Gas Commission. 10 e e Well Construction 20AAC 25.252 (c) 6 Wells will be drilled to the indicated bottom hole locations and to a final vertical depth of approximately 9,950 feet. The drilling program calls for maintaining accuracy that will allow hitting within 250 feet of the target. All construction requirements exceed the specifications required by the State of Alaska Oil and Gas Commission regulations. Construction details are included for well WD-2. The casing-cementing program for WD-2 is depicted schematically in the Exhibit 11. The surface hole will be logged as specified to ensure that the surface casing is well bonded to the formation below the permafrost. The use of Class-G cement as tail slurry around the casing shoe will ensure good zonal isolation around the bottom of the casing. A full logging program will be run in the lower hole. The injection casing will be cemented with an excess volume to ensure the cement top is at +/- 6,600 feet TVD. Cement bond logs will verify zonal isolation. Both surface and injection casing integrity will be verified by pressure testing. The tubing by casing annulus will be isolated above the injection zone by a packer. A landing nipple to accept a wire line deployed downhole check valve will be installed in the tubing string below the permafrost. The annulus will be brine filled with a diesel cap for freeze protection. The tubing will be heat traced to provide heat should it be required during extended shut-in periods. Both the tubing and tubing by casing annulus will be pressure tested to 3500 psi. Should the pressure test fail the tubing will be removed and the problem corrected before the drilling rig leaves location. The wellhead assembly is shown in Exhibit 12. The wellhead, controls, and monitoring instrumentation will be enclosed in an insulated and heated well house. Flow lines to the well will be heat traced and insulated. 11 __ _"'___~___~_"__"__'------:--'.--"'"__~-"'----""-'- .~. D" e e Proposed Drilline: and Completion Proe:ram : Well WD-2 Surface location: ASP "X" 386,665 and ASP "Y" 5,976,560 444' FSL & 2052' FEL See 32, T11N R5 E ASP "X" 388,230 and ASP "Y" 5,976,240 149' FSL & 482' FEL See 32, T12N R5E 250 ft Radius (+/- 250 feet) Target location: Target Accuracy Estimated start date: 1 st Qtr 1999 Maximum angle: Kick off depth : 18 degrees 3000 feet Wellbore azimuth: Kelly bushing (KB) elevation: 104.5° 57 ft AMSL Item and Depths Subsea TVD (*BKB) MD (*BKB) (*below kelly bushing @ rig floor) 16" Conductor ±60 ±117 +/-117 Base Permafrost 800 857 858 9 5/8 Casing Shoe 2726 2783 2800 Top Confining Zone (U. Kingak.) 7360 7417 7646 Base Arresting Zone (L. Kingak.) 8640 8697 8995 (Top Injection Zone - Sag River) Lower Injection Zone (Ivishak.) 9105 9162 9485 Top Lower Confining Zone (Kavik) 9750 9807 10164 Well Total Depth 9900 9957 10322 (7 Inch Casing Shoe) 12 -'~.'-- "r--. e - Loeeine Proeram Open Hole: 12 1/4 Surface Hole: GR/RES/NEUTIDENS (TD to Surface) 8 1/2 Hole: GR/RES/NEUTIDENS (TD to 9 5/8 shoe) Cased Hole: Cement bond log from 9 5/8 shoe up to Surface (consistent with EP A request for Class I disposal). Cement bond log from total depth to top of cement. MWD survey while drilling. Freeze Protection Plan The 4 Y2 X 7 inch tubing annulus will be freeze protected with diesel from the surface down to the base of the permafrost. This interval will also be heat traced. Casine I Tubine Specifications Csg/Tbg Tension Burst Collapse ~ OD Wt/Ft Grade Conn. k lb. lID psi Conductor 16" 62# H-40 WLD N/A N/A N/A Surface 9 5/8" 36# J-55 BTC 564 3520 2020 Production 7-5/8 29.7# L-80 STL-FJ 683 6890 4790 Production 7" 26# L-80 BTC 604 7240 5410 Tubing 4 Yz" 12.6# L-80 STL-FJ 191 8440 7500 Tubing 4 Yz" 12.6# L-80 BTC-Mod 209 8440 7500 13 Cement Volumes 9-5/8 Inch Surface Casing: Measured Depth: Basis: Total Cement Vol.: Lead Slurry Vol.: Tail Slurry Vol.: 7 Inch Injection Casing: Measured Depth: Basis: Total Cement Vol: e e 2,800 feet 300% annular volume excess over permafrost 50% annular volume excess sub-permafrost 80 foot shoe track (12-1/4 x 9-5/8" annulus) 1,965 (cu ft) - subject to revision 1,789 (cu ft) +/-410 sx Arctic Set 3 Lite at 4.47 cu ft/sx (from surface to 300 feet MD above section TD) 176 (cu ft) +/-150 sx Class G cement at 1.17 cu ft/sx (last 300 feet of annulus to section TD) 10,322 feet 500 feet MD above top Alpine, with 30% excess. (8-1/2" x 7" annulus) 608 cu ft, +/-540 sx at 1.16 cu ft/sx. (subject to revision based on hole conditions) Construction Procedures 1. Set and cement 16 inch conductor casing. Move in drilling rig. Install diverter and function test. 2. Drill 12 1/4 inch hole to the surface casing point. Rig up and run electric line logs. Run and cement 9 5/8 surface casing. Install the wellhead and blow-out preventer (BOP) and pressure test per AOGCC regulations. 3. Run cement bond log from landing collar to surface at this time or wait until open hole logs are run. 4. Test casing to 2,500 psi for 30 minutes. 5. Drill 8 1/2 hole through the proposed injection interval to total depth (TD). Rig up and run E-line logs, and cement bond log if not run in step 3. 6. Run 7 x 7-5/8" inch casing to TD. Cement casing string as per program. 14 e - 7. Displace well bore to clean seawater. 8. Run a cement bond log from TD to the top of cement (TOC). 9. Run 4 Y2, 12.6 #, L-80 tubing with heat trace wiring and down hole check valve nipple at +/- 1,300 feet. Freeze protect annulus with diesel. Test tubing and tubing-casing annulus separately to 3,500 psi. 10. Install the wellhead and test to 5000 psi. Release drilling rig. 11. The drilling fluid program and surface control system will conform to the regulations set forth in the AOGCC Regulations - 20 AAC 25.033. 15 e e Waste Sources and Characteristics 20 AAC 25.252 (c) 7 Class II wells are defined as wells which inject wastes brought to the surface in connection with oil and gas production, with natural gas or liquid hydrocarbon storage operations. Class II fluids may be mixed with other wastes from plant operations; unless those wastes are classified as hazardous waste under 40 CPR 261.3. Typical RCRA exempt wastes which are acceptable for injection can include the following: Drill Cuttings, Drilling fluids, Cement fluids, Completion fluids Workover fluids, Stimulation fluids, Frac Sand, Produced Water, Crude Oil, Production Vessel Sludge/Sand, Fresh or Sea Water, Natural Gas Liquids, Rig Wash, Well Cellar Fluids, and others allowed under 40 CPR 261.4. Typical Injection Stream Calculations indicate that the Sag River and Ivishak formations can not be fractured sufficiently to dispose of a large volume of solid material. There is concern that screen- out or plugging will render a well or disposal interval useless. Therefore the disposal of drilling mud and cuttings is not envisioned for these wells. On occasion, some mud will probably have to be directed to them but cuttings from a grinding plant would only go there on an emergency basis. Other exempt solids will also be directed elsewhere whenever possible. Exempt wastes routinely generated by well workovers, contaminated crude oil, vessel sludge/sand, diesel/methanol usage, spent acid, fracturing operations, snow melt, and plant upsets could total 4 million barrels. Produced water disposal could be expected to 16 e e total 14 million barrels before the rate reaches 10,000 BPD. When the field rate approaches this level, water-polishing equipment will be installed to allow reinjection into the oil reservoir. Over a 20-year project life, produced water would constitute about 80 percent of the waste stream. Other exempt waste activities would account for the rest. Injection Rates After plant startup, but prior to significant produced water breakthrough, the injection rate will range up to 300 BPD. Produced water breakthrough from waterftood or EOR operations is projected to occur about year five and build toward 10,000 BPD by year fourteen. If this projection is accurate, the disposal rate will reach 330,000-360,000 barrels per month in this time frame. At some point before the 10,000 BPD rate is reached, it will be advantageous to start reinjection into the oil reservoir. The disposal rate would then drop back to the 300-500 BPD range. 17 ,.._.________._ '____m_. --~-----,-_. ..- +._------~~_._._._-- ...._._-.-._-,--~---'~ e e Injection Pressure 20 AAC 25.252 (c) 8 The following table shows the range of injection pressures that are estimated to occur through the life of a single well over many years. They reflect behavior of the tighter Ivishak formation since the Sag River is clean sand with significantly better porosity and permeability. The Ivishak sand intervals containing clay, are tightly cemented, and are interspersed with enough shale stringers that it will be hard to push dirty fluids into a completion interval for a long period. The smaller pore throats will progressively become plugged in the region around the wellbore. This damage zone will restrict well injectivity so that in order to maintain the required disposal rate, it will be necessary to stimulate or fracture past the restriction. It is anticipated that near-well bore fractures will be required to establish new flow paths to undamaged rock. The projected pressures reflect what is expected to occur because of variations in lithology and changes in the well injectivity index with time. Should use of the Sag River formation be required, fracturing would be much less prevalent. Further discussion on fracturing is included in the next section. Surface Iniection Pressure Early time frame: No fracturing of the injection zone required but assuming zones are originally slightly over pressured. 1700 psi Several years into field life: Some fracturing of the near wellbore region may occur to get past early plugging caused by dirty fluids. Assumes a clean sand fracture gradient of 0.65 psi/foot. 2200 psi Later in field life: Fracturing of the near wellbore region is required. Assuming a tighter shaley/sand fracture gradient of 0.70 psi/foot and a higher injection rate, this level of pressure is required to over come estimated fracture mechanics and tubing frictional losses. 3000 psi Maximum injection pressure: This generates a static fracture gradient ranging from 0.77 - 0.80 psi/ft. If friction losses are taken into account these gradient values would be smaller. 3200 psi. 18 "~;,F'~_ ...,<~;._"""". ~ ',_, ;·".~,.',"'W;'¡'k e e Waste Confinement 20 AAC 25.252 (c) 9 The following discussion focuses on the possibility of failure to keep injected waste confined to the subsurface strata located below the upper confining zone. The purpose of the assessment is to provide discussion on potential problems, how these problems will be avoided, and how they will be handled in the unlikely event that they occur. Risks of interest that must be considered are as follows. Uncemented Wellbores and Wellbore Channeline: No oil reservoir development wells will penetrate the upper confining zone. Development wells will be drilled from two gravel pads and will reach a depth 400 - 500 feet above the top of the upper confining zone. Production well long casings will be cemented across the oil reservoir and 500-1000 feet into the shale that lies above it. There is no confinement risk associated with wellbore leakage due to development wells. The only leakage that could occur would be associated with channeling adjacent to an injection well. This would be detected by channel logs and would be repaired by squeeze cementing. Verification of the repair by pressure testing and logging would follow. Natural Faultine: As shown on the structure maps and on Exhibit 13 there are normal faults cutting the injection and arresting zones in the local area. They are all minor compared to the thickness of the over lying Kingak shale. At this depth sand intervals will generally produce a rubble zone that can permit flow along the fault plane; however, the brittle shales typically do not follow this pattern. Experience has shown that it would take a very large pressure differential to create flow along a normal fault where dense shales are juxtaposed against each other. At Prudhoe Bay, major faults extend from the main oil/gas reservoirs at +/- 8500 feet to the Cretaceous water disposal zone at +/- 6000 feet. With a large gas cap present in the Ivishak, obviously there was no upward gas migration or the Kingak shale would not have become the cap rock for hydrocarbon accumulations. By the end of 1996, the main oil reservoir pressure had declined 1000 psi. Conversely, the over lying Cretaceous aquifers have been over-pressured several hundred psi due to a billion barrels of produced water disposal. This imbalance creates a pressure gradient of over 0.4 psi/ft (1000 psi/2500 feet). No flow has been detected from the Cretaceous zone. 19 _ ___..._ ___.~,...__. .. _~_~.___~_~___._....._._.__._______.. __ ___________.__..______m ---c-.-.---~-_,--._..~ e - Pressure buildup calculations indicate that the fault nearest the first disposal well might see a 100 psi pressure rise. If the 0.4 psi/ft gradient were a limiting, worst-case leakage condition, then a 250 foot thick arresting zone would contain any potential upward migration. These faults will not permit migration into the confining zone. No confinement risk can be anticipated due to their presence. Fracturine: of the Upper Confininl! Zone Well bore damage is expected to accumulate from the periodic disposal of dirty fluids. This will necessitate wellbore stimulations and possibly near-wellbore fracturing to get past the damage zone and maintain the required disposal rate. The fractures should not be extensive since fluid leak off will be high once new rock is contacted. Because of the lithology contrasts, lateral fracture growth would be expected to be greater than what occurs in the vertical dimension. If the shales fracture at a gradient of 0.80 psi/ft and clean sands at 0.65, the stress contrast becomes 0.15 psi/ft. At an arresting zone base of 8,650 feet, this generates a stress contrast of 1297 psi. This indicates that should the Sag River Formation be perforated, and a fracture developed, it could not be expected to penetrate the overlying Kingak shale. As an effective buffer, if there were some vertical growth above the Sag River, it would never penetrate the 660 feet of arresting zone and reach the confining zone. Confinement risk associated with fracturing is almost non-existent. Comparison With Similar Projects There are similar but no direct comparisons with other North Slope disposal projects because dirty water/wastes are not injected into these formations on a long-term basis. However, since 1985, produced water and seawater injected into 206 Prudhoe Bay Sag River and Ivishak wells has totaled 6.146 billion barrels. At the Endicott field, 506 million barrels has gone into 26 wells and at the new Pt. Mcintyre field, 205 million has gone into 13 wells. The average per well ranges from 30 MMB at Prudhoe to 16 MMB at Pt. Mcintyre. Many of the above wells have minor fracture systems associated with their injection zone, some caused by thermal fracturing due to injection of cold surface waters and others by fracturing past wellbore damage zones. Some of the fractures are permanent and others probably open and close. In the rare case where injected fluids are not confined to the desired sub-interval, it is usually associated with a poor casing cement job. Fluids are ail confined to the Ivishak gross section. 20 ~~---_._. e e Summary The risk of non-confinement of injected wastes must be viewed as minimal to non- existent. A competent upper arresting-confining zone and successful large scale water injection at other locations, coupled with proper well monitoring, all indicate wastes can be confined and no environmental damage result. 21 -"'~-~.,--~-- ..~-._-~_._~--_._--_.-- ...,,---~-"~.----~..- -~----~.~._- e e Formation Water Salinity 20 AAC 25.252 (c) 10 Salinity Calculations In the Alpine project area only the Neche1ik #1 well has been logged from surface through the injection zone. No clean sands were encountered above the confining zone; however, the Alpine #1 well did cut some thin Albian sands at 5150-5204 feet and Bergschrund #1 found a thin shelf sand at 4220 feet. Salinity calculations made on available intervals resulted in the following. · Bergschrund # 1 (4220 feet) 15,000 ppm NaCl eq. · Alpine # 1 (5150-5204 feet) 15,000 ppm NaC1 eq. · Nechelik #1 (Sag River Formation) 18,000 ppm NaC1 eq. · Nechelik #1 (Ivishak Formation) 17,000 ppm NaCl eq. The methodology used and results obtained from salinity calculations on the Albian/Nanushuk Shelf sand stringers (Alpine #1 and Bergschrund #1), Sag River, and Ivishak Formations (Nechelik #1 well) are as follows. The calculations use the standard Archie correlation and log derived data to obtain an Rwa value using the following formula: Rwa = (porosity) m (Rt) / a ........... with the following definitions: Rwa Porosity Rt Resistivity of water necessary to make a zone 100 % wet Porosity in decimal from logs Formation resistivity from logs Cementation exponent Assumed to be 1.0 per the Archie correlation m a The cementation exponent is the variable of least certainty. The best source for determining this value is from special core analysis (SCAL) when available. No SCAL is available for the Albian interval; however, such data does exist for analogous fine to very fine grain sand in the area. This data has yielded: 22 .. '->"'~'!" '.~ .<)-',.,>" >." .~, ,.-."-' ~~~...~.-~". e e Alpine section SCAL from the Alpine #1 well Sag River SCAL as documented in ARCO TSR 95-46, internal report m = 1.55 m = 1.6 The following exponents will be used in these salinity calculations. Shallow intervals (4000- 5000 feet) Sag River Formation Ivishak Formation m = 1.6 m = 1.7 m = 1.8 . Nanushuk Shelf Sand: (Bergschrund #1 well depth 4220 feet) This shelf sand is evident in two wells at approximately 4200 feet subsea. Rt = 4.0, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The calculation yields an Rwa equal to 0.356. Using Schlumberger Chart Gen-9 and a formation temperature of 80 degrees F, gives a salinity of 15,000 ppm NaC1 equivalent. · Albian Interval: ( Alpine #1 well depth 5150-5204 feet) There is a collection of thin sands in this well and a complete set of logs is available. Rt is taken from the shallow MWD tool because of minimum exposure time to invasion and superior vertical resolution in three foot thick beds. Porosity comes from the density log. Rt = 3.2, Raw density = 2.28, m = 1.6, Porosity = (2.65-2.28) / (2.65-1.0) = 0.224 The Calculation yields an Rwa equal to 0.293. Using chart Gen-9 from Schlumberger chart books with a formation temperature of 100 degrees F, gives a salinity of 15,000 ppm NaCI equivalent. . Sag River Formation: (Nechelik #1 well depth 8432-8480 feet) This is a thick, clean, uniform sand interval with a complete set of logs. Rt = 1.9, Raw density = 2.32, m = 1.7, Porosity = (2.65-2.32) / (2.65-1.0) = 0.20 The calculation yields an R wa of 0.145 and with a formation temperature of 165 degrees F, produces a salinity value of 18,000 ppm NaCI equivalent. 23 e e · Ivishak Formation: (Nechelik #1 well depth 9420-9460 feet) This lower sand member has the lowest resistivity and greatest SP excursion. Rt = 3.3, Raw density = 2.35, m = 1.8, Porosity = (2.65-2.35) / (2.65-1.0) = 0.18 The calculated Rwa equals 0.15 and with a formation temperature of 185 degrees F, a salinity of 17,000 ppm NaCI equivalent is obtained from the Schlumberger chart. Water Sample Analvses The following water samples were obtained from drill stem and production tests in the general Colville Delta area. · Colville #1 well 7922 feet · 14 miles Northeast · 22,485 mg/l TDS (tested) Shublik Formation · Colville #1 well 9073 feet · 14 miles Northeast · 24,004 mg/l IDS (tested) Lisburne Formation · Kalubik #1 well 5050-5250 feet Albian Interval · 17 miles Northeast · Flowed 151 barrels to surface · 24,300 mg/l TDS (average of tests) · Kalubik Cr. #1 well 9047-9188 Lisburne Formation .' 21 miles East · Flowed 325 barrels of water · 21,847 mg/l IDS (tested) .' Mukluk well 7490-7520 Ivishak Formation · 23 miles North · Flowed 984 barrels of water · 11,000 ppm chloride tested · 18,150 mg/l IDS (calculated) 24 "~"'.',:~~". e e · Mukluk well 8145-9860 Lisburne Formation · 23 miles North · Flowed 1750 barrels of water · 11,000 ppm chloride tested · 18,500 mg/l TDS (calculated) Laboratory data and other reports can be made available if desired. Reference is also made to the Class I Well Permit Application, Appendix D, previously submitted to the Commission in September 1997. 25 _________.____..,.__~_~~..___.____ _ ·__~-_.______..u,_·___ "...,..__~__ ___ ." .q-,', 0'---;' ~ ....., e e Aquifer Exemption 20 AAC 25.252 (c) 11 Aauifer Exemption No underground sources of drinking water (USDW) have been identified within the Colville River Unit area. Since there are no USDW's in the Alpine field, an aquifer exemption is not applicable. The Colville Unit Area includes; Township 11N Range 4E - (Umiat Meridian) Sections 1-5 all, 7-16 all, 21-27 all. Township 11N Range 5E - (Umiat Meridian) Sections 1-24 all, 29-30 all. Township 12N Range 3E - (Umiat Meridian) Sections 25-27 all, 34-36 all. Township 12N Range 4E - (Umiat Meridian) Sections 20-21 all, 22 excluding portion in Survey USS 9502 (2), 23-27 all, 28-32 excluding portions offshore, 33-36 all. Township 12N Range 5E - (Umiat Meridian) Sections 1-36 all. Township 13N Range 5E - (Umiat Meridian) Sections 9-10 all, 15-22 all, 26-36 all. North Slope Resident Water Supplies The Alaska North Slope is populated by approximately 6,200 permanent residents in eight communities. Because surface water is plentiful, seven of the eight native villages on the North Slope rely on surface water from lakes or lagoons for their water supply. The closest permanent resident population at the village of Nuiqsut (population 450) is approximately 9 miles from the Alpine project area. In the North Slope area, only the village of Anaktuvuk Pass (population 325), approximately 170 miles south of Alpine in the Endicott Mountains, has a subsurface well for their public water supply. A table of North Slope demographics for permanent residents and their potable water sources is attached. 26 ~. -.--"<.Cr,>""...." ,"'" ',<~~~_;'1",-.':~"'-' e e Approximately 3,000 industry workers temporarily reside on the North Slope in one of six major camps. The transient populations residing at operator and contractor run camps for the North Slope oil fields all rely on surface water for their water supply. Even the base camp at Endicott's offshore facility treats seawater for its drinking water supply rather than uses a subsurface source. A tabulation of these potable drinking water systems and their operating costs is attached. The Alpine facility will also use surface water as its potable source. 27 __________m_ ..."__<____ ~ ._----~-~-._-,--- ._____'____"'m_.__ _._-~~....- ~,~ e e Potable Water Sources and Demographics Villages of the North Slope (October 1994) Distance PWS ** Potable from J.D. Water Village Population Alpine Number Source (Miles) Barrow 3404 150 620078 Isatkook Lagoon Wainwright 570 210 620086 Freshwater Lake Kaktovik 280 170 620248 Freshwater Lake Pt. Hope 711 350 620426 Freshwater Lake Nuiqsut 450 9 620264 Freshwater Lake Atqasak 220 160 620094 Surface Lake Pt. Lay 150 290 N/A Surface Lake Anaktuvuk Pass 325 170 650057 70 Foot Well ** Public Water Supply Identification Number 28 ....~ e . Potable Water Systems North Slope Oil Field Area (October 1994) Oil Field Camps Approximate Population Potable Water Source System Size (gal/day) Operating & Maintenance Cost (¢/ gal) BPX 800 * Lake 102,000 3 Prudhoe Bay Base Operation Center ARCO 1100 * River 176,000 1.0 Prudhoe Bay Base Operation Center ARCO 350 * Lake 76,000 2.1 Kuparuk River Base Operation Center Milne Point 150 * Lake 30,000 1-3 Central Facility Endicott 120 Seawater 20,000 1.5 Base Operation Center Kuparuk 130 River 24,000 1.5 Industrial Center Pump Station 1 50 Purchased N/A N/A Deadhorse 320 River 50,000 1.5-2.0 Service Area .- Potable water also hauled to temporary drilling rig camps. 29 ~-----'---'---- .'- -*-_._.,---.-._----,~~-<--. - ·'r··~"·~~J·"·- e . Mechanical Integrity 20 Ace 25.252 (d) (e) Mechanical integrity will be verified after well construction by testing to 3500 psi as outlined earlier in part 25.252 (c) 6. This will conform to 20 AAC 25.412. The casing- tubing annulus pressure will be monitored regularly and reported to the Commission on Injection Report Form 10-406. The tubing-casing annulus volume will vary, and the annulus fluid itself will expand and contract due to temperature changes. At the present time it is hard to specify exactly what high-low annulus pressure limits should be established to trigger a warning and possible shutdown. The exact points will need to be established once a repeatable pattern of fluctuation has been established. This can be determined after several months of performance that would include both the summer and winter ambient temperature swings, which affect this operation. Channel logging to verify fluid confinement will be performed as dictated by operating events. Reservoir pressure testing will be performed as needed. 30 '~T.~,..,+--...,.""",~,,,, e . Wells Within Radius of Investieation 20 ACC 25.252 (h) Bergschrund #1 and development well CDl-22 are the only wells within 1/4 mile of the disposal area. Bergschrund #1 does not penetrate the injection or arresting zones but does touch the top of the confining zone. It's completion report and abandonment schematic is attached. Well CDl-22 does not penetrate the confining zone. No corrective action plans are required. 31 ~ · · · · · · · · ,.. · I I I I I I - I '_11I_. STATE OF ALASKA .tl¡~ nEflTIAl ALASKA OIL AND GAS CONSERVATION MMI WELL C.PLETlON OR RECOMPLETlO.EP ~ .. (' . III........ OIL 0 GAS 0 S&MINDID 0 2...crI c... ARCO AiMIIL Inc 3~ P.O. &ax 1D0380. AI.cft....QI. AI( 19510.œe0 .. ~crI"'._ 2130' FNI.. 1eacr Fa. see 3Z. T 12N. R 5E. UM AlT., ~..... NA AI T aIIII DeøII '·~æD I!J SSMCE 0 r .....-- ..... "...4tnt OM SA . API__ .103-20207 8 UIII.~__ NA '0 w.e...... BERGSCHRUND ., " FIIIII_ .... 2102' FNL 1652" FEL. SEC 32. T12N. R5E. UM 5 ElMaølII........ a. DF. a.) WILDCAT 16 ~ ~...-........ ADL. 25558 ,.. 0.. CanID.......... I t5 ~ ~...... 116 No. crI Coß$ ..1-4 OU1u.M(ABAND' NA'" MSL/ NA 11 ilL AI ......., þD ~.... SSSV .. 121 "-:- crI .........- "tIS I!JIMD NO 0 I NA ...tom ... KB ABOVE SEA LEVEL;4O' 12 o.a __ "a. T.o. RMa.a 13-1MrolW 2foMuolW t7 TIIIII DØft fIoD>1VD) ,. ~...a.. IUDt-TWI 7sa:r MD. 75D1.1VD SURF 2Z Type EIIanc. 0INr &.agIJ fUI ZJ owr.tSFUGR/DIPCI SONIC. MSCnGfl FtooIIGl MDT"''''"', SWCIQIII CASING. LJNEIIt AND CEMEN11NØ REICCRD SEnNi DI!P'TM lID 'T'OfI' Imt SURF 110' SUAF 11O'r ,CASING SIZE '15" ,.as- wr 82.5e 53.se MDLE SIZE M" 12.25'" CIIoINrJI!IXJIÐ 2DD SX AS! CUT 212 SX ASII1 cur. .17 SX ClASS G CUT 105 SX AS! TOP JOB GO SX CLASS G CUT GRAœ twO l-4lO r 2te l-4lO SURF L5" 7'" ~ ~"'__D". . .,o.1'VDIIIT...,___ ......--~ NA ,... RECCAD DI!II'IM lIEf fMD) NaŒR tIEr fMDJ 25 SIZE NA . ACID. FNCTURE. CElÆNTsca.- Ere ~ tN'ÆIWAL CIIDI AImUNT & ICIfØŒMA11!NAL USED esrro8l32" PERF SQUEEZE 75 SX CLASS G cur r1 DIll f'ftI ,. ~'TIST r"c..-~.....IC.) ~FCR CIIIAk GMoIICF 1DfPBIaD I CM.C&I.A'ÆD awtOUR RAnI WA~ ØOŒSIZE I GMoQLM11O WA~ QlLØMVITY-API..... 'V VI DIII..T_ ",T_ CMIIg~ AM T.-.g ~ . callIE DATA ....11 __..._......,.--.---...............-. ...._~ CIII&A& GMoIICF .,0.........., T Lt.. .ca...g,____ ,..104G7 Rer. 7.'" ......-. CXININBJCIII.P68.A... DISPLAY .-_.. .._--~_...~_.__._~---~-- ---~-_.--+--_.__.._._._~_._.---_.-- eaa.n!.. ~~.. II ~~~~~d.. ~~ ..~~~ !~Und 'ew.. L................................-...........·.·.·.~~ P." ea u..&ø 3· b I d '" . _ f , ,.... , , , " 'v .. - . '" p ..,,,er e ow· groun . ~. - , ..., , , , , ~, , . I t -'" 0...-" 1_.. ..: ..;,:...;.,..,......,..,..,..,..,..",..,... n Ci......IlOI"I """,II.. we ..a.. to eRn marker .- :¡:...# ..,....,..,..,..,..,..,..",..,.. ARCO - 8_ .-1''''-- '1 ~,"::,' .:t,.._~..,..:'.........~<,..,.. Iñ........ua... .......~ ':';':''''''~'~ ~,~': ADL-25558 ..' .'..:.¡ - . +' ' . , , .t API' 50-103-20207 ~ . ,'" "" . " '- .- ~.'.'? :". ·Z":": .:..:.. ..A 2130' FNL. 1600' Fa. S-32-T12N-RSE. UM :'. .-:-:t-, .~',-. -tp.,','. .,...,... .....;J .... a ~ ~ ''''.,.. ~'ra' " . ......:' .. ~_.....:::.:;~..:..: .:..:~.:.::. iwi;. .~- . ~",,'" ':¡"','.. ',"'/' . :.-.. .~..--. ... -.. .. . .. .. . .,.: . ....., , II , , :....-:. -~..,... 10.5 PPD .,..,.. -:' .:' . . . ......,... Brine .,..,.. . ~"'4 ',','" ~','. ',','" ... ... . " , ...". " " ...... . ... ... - .~·;·z..~·:",',· .','...:..:..:... .:.;.....:.~"'" ' . " .!\..~.:.. ~!.:::; -:::...;¡, ", ...... . , ..., '-::'. \:~...'"!~ ~:..-:!...::.." " '.. ., " ...:(....~.~.. :!.~::..:..¡.:.." "'11 '.', " ....~~.!..\~~\ ...~...::..::...J '11" ., " ...:!.............. .·l.·r"'r~"" ..) ~ .. '-·r·r.V.~ Calc. TOe 0 1415 ~.·:.:r.V:·?,..'.. ,'..'..'..'..' .."-'..' ,-'rl¡F¡;~ . 1:..1;..-;...",'..,',',',','...'" " ...::~\~:.: .:.......!.-.." , ... , , , , , "" .:.~!.\... ANNUl US,:r.:r.·r~ ....,..........ß.. '-·I"-:I·{I·. ....\·I.y, ..., , , , , r~" '.. .\... ,;:".'..~".-,' '" , , , " '~ ' "a.,'-.::...... ....~\!iV:~ ,'.. " " ,,' " "',, ' ""at,;,:.:..:·.:.: Cement Volurn, .rNNX/..'.. " ...,; ('''''-:I\:·:·ì:~ .... ......~, , , " .... :..:.. B"""" p..... . 1830' 102 Sx Class G w/1% CaCt2:!.::!.~.:!.:. ",' ;,..,'-:!.\.::-:!:\.;.... -" .......... ",' þ , " ·1······.. Densitu-15 B ppg -¡..:...¡ ~,. .,:':rItJ:..~\\:\. ··7- . ..-..... .. .. ~';I" Yield=1.16 cu. tusx .. . ... VoIume--21 bbls HiIr. 53.51. L-IO. BTC. a.sacr ~ drtft and ( 110T TVDIMD) 151 Sx Arctic Set I 10.5 PPD Densrty=1S.7 ppg Brtne Yield=O.93 bbutt Volume-2S bbls I I SURFACF PI Ur. TOC 0 :rr RKB 3' below ground level ì Bridge Plug 0 298' I Cement volurn, 75 Sx Arctic Set I Densitya15.7 ppg Yield=O.93 cu. tusx Total Volumea12.4 bbls Cement to 3' below ground level. I I I 9-S1S-x7- I I I I Total V0turne-46 bbIs Annular Capacitya.0232 Calc. Height=2000' bblltt I 9-51S- SHOF P' Ur. I Cement volume 75 Sx Class G w/1% CaC12 Densïty.15.8 ppg Yield-1.15 cu. tt.Ju Total VoIumea15.4 bbls Calc. Height.415· I I PFRFORATlONS p, Ur¡ Cement volumt 75 Sx Class G w/Z'J. D800 Denaïty.15.8 ppg Yielda1.15 cu. tua Total VoIurnea15.4 bbI5 (8 bbIs squeezed below CR. 7-1/2 ÞbIs on top of CR) Calc. HeigtIt-21S below CR 2DD' abcwe CR 1r; 1Z.58I. PES (110' 'TVDIMD) level CO\f\Œm\~l ~.....~.."l.:,,¡ ':.,:;..";:: TOe . 6133' (CETICBT oa.d £151M) ~:?:""'1 :.?;::;.:~ ~~,,:i;¡,~ ..~·t-:':..'" ~II,',. ..:...... .,,~,,\~, , , , , ,>:;V",!: Calc. TOC . 6650' ~..Y·."l.<;.' " " " " ,,.:~!.~!... ~,¥\V... ,',', ',', "..::!~::... ~"~"~~., .. .. .. .... ·-:r~:~ ~íV,V: :..:.:~::... tNN: ·W·::;~ Cement Retainer 0 6850' :':\1 \:~:\ l,,"f..&'" , , " ..\::.¡:: !,\...I'~ ,', "',',', 'A·.....:.· -:l!-"'-' , .., .., .., .., .. 4:{!: Perforations 8I7T-6932' '1'';;:>' .. .. .. .. '~r"'r·. ~*~ 1;,~~ tNNi 10.5 - .;'11\\\ ~"'~/' ~. ..\..~\ f..:.¡"v, Brine ·...'1..-:¡:: :..~..!, ','I."!: .,....'....." '{/~'·. Z\~\~*'I::: ;~~.;:/~!;~f.:: r.2II. L-IO. BTC ~\.: :.... . .....:. .:......;~ (7411' TVDIMD. 7311' PB'ID) c-..,.,.JØ71 tIIIIIft ,BERGSCHRUND WI ;PL.UG AND ABANDON SCHEMAl1C o ~ w E2 E::) _Lead CeIMnt . Tal CeIMnt .eem.t Plugs .' Gravel FBI WLM· .,tMM IIIIIIIIIIIIIII - Alaska, Inc. <> -"'~ !iii , Scale: 1":= 4,000' 4-7-98 EXHIBIT 2 Alpine Development Project Surface Faciiities 97062506C01 ARC a Alaska~ Inc@ ~III... Created by Michaelson Dote plotted: 30-0ct-98 Exhibit 3 Spider Map Plot Reference is C01-20/13 Vers.#1. Alpine Development Project ~~ Coordinates are in feet reference slot #20. Proposed Well Courses True Vertical Depths ore reference Estimated RKB. Central Facilities Pad 10. .... INTEQ East (feet) -> 2250 2000 1750 1500 1250 1000 750 500 250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 1500 - ~ 1500 1250 - 1250 - 1000 - - 1000 .J.,/¡o ^ 750 - - 750 ^ I I r--. Z +-- Q) 500 - - 500 0 Q) -, -+ '+-- J '-" £ ,,-.., +-- 250 - 250 --+, ?- m 0 m z -+ "-' 0 0 r--. 2400 ~ (f) +-- 0 Q) Q) C '+-- 250 - -+ "-' J £ ,,-.., +-- --+, - ::J 500 - - 500 m 0 m -+ (f) "-' I 750 I V 750 - 11,'119 - V 2,,/J.t 1000 - - 1000 1250 - - 1250 "",1''eI 1500 - <o/~ - 1500 2250 2000 1750 1500 1250 1000 750 500 250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 2750 East (feet) -> i- II I I ! i . I i ~ j ! I ; I I \ ! I I ; ! ; ! i ; i i ! I I r i I ! I I J --- . -- ;~----- ~.._, ~ -.--. ! -,.'--, .. ) ~-~- ~- --_.~. ~ j .~ i ! -i - i i i i ! I I -..-.. ¡ ~-~---_.~ ~ .... t ¡ . m -- ; i ¡ i ¥~æ0i;ii0;'!¥¡fiE ! ¡[ ~, ¡; . , jl i ¡ ;~ . ¡ i î ¡ l ¡¡I j I ¡ _ I "'-. - l - , ----_. .: J ¡ ¡ I;! r : I - I I - I i - ~. I ¡ I i·::' i I i I i 1 11- ! I ! ," ". #. ,~ .. 'Ii I .,~t1 I I ,_.,~--..,. ttl . ~ 3 .- I ¡ ¡ ¡ I '-h' ¡ ¡ I ! I -", i I ; i ! ! ""- I~ ) -~ 1 i ¡ I i ." .' J + 'i'" ' - -~ , i, I', , .:.:: wi :~ , !~I ! ~. . ,- j ; ¡ "., ; .~ , ., ¡ < ¡ I I ; , ¡ I "II I - ¡ , I I ¡~r'< , . "¡ i i ¡ ¡ i , 1IIIIIIIIIIIIIIIIIWJIIII!IIIIiIIIIIlII!iII!IIIIIIIBWliØllllllillllllllIIØi11IIIIi!IIIIIII! N' _... 1!IIiIIIJII!II!II!IIII ifIi!IIIIJI 111!i111111!11IIØØJIØ IiIJIifI!!I!' æ Shallow Marine River Fm WDI) .65 I 2.65 I OIt,M G/CJ ~ u - ....... ,415 1.500 1.600 1.700 1.800 1. 900 ARCa Alaska Alpine Project Seismic Section SW ~ NE Transect 1 97071102A01 97071101A01 : Well locations are depth. Wells do not penetrate the confining zone. 10 Alaska e Project Permafrost subsea) 97060002AOO 2 ! 1 j xhibit 11 ~2 roposed 0 pletion AMSL KB I I I I I I I I,.. " ppf J BTC Surface Casing @ 2800' MD Drilling Mud I I c# I I I I I I I I I I I I <: 4-1/2" 12.6 ppf L-80 tubing FJ to 1200' M low 1200' " 29.7 ppf L-80 STl-FJ to 1200' ppf L-80 Mod to TD rVD Depths 7152 7417 8697 8747 9162 9807 Cement ~""""""""" """""""""""""'. Confining Zone :-...,"""""""''''''''''''~ ~"''''''''''''''''''''''''''''''''~ Arresting Zone :-...,,'''''''''''''''''''''''''''''''''''~ River 9 lagra 16" Conductor @ 117' MD Electrical heat to +/-1 MD Base Permafrost @ +1-800 ft TVDs$ Camco 4-1/2" "D8" Nipple (3.812" I with Model "A3" Injection Valve 125" I at-1300'MD Packer Fluid: , 8.6 ppg KCL brine with diesel freeze protection to 1200' TOC @ +1-6600' TVD (500' above Alpine Reservoir) Baker Model SABL-3 Packer at +1-8700' MD HES "XN" (3.725" ID) Injection perfs 8995'-10,164 MD 10, MD i 1 Well Schematic WD-2 Wing Valve Master Valve WEll HEAD DESCRIPTION - SINGLE TUBING HANGER! WELLHEAD - 4 1/2" - METAL TO METAL RING SEAL ASSEMBLY - SINGLE MASTER VALVE - MANUAL - SINGLE WING VALVE - AUTOMATED FOR SHUT IN - PRESSURE RATING - 5000 PSI - WEll HEAD TEST PORTS - AS REQUIRED - COLD WEATHER METALLURGY - TYPICAL N. S. - CORROSSION METAllURGY - WASTE DISPOSAL WEll - ENCLOSURE (INSIDE INSULATED WEllHOUSE) Tubing/Annulus Valve 13 Southwest Northeast 97072101AOO :~''t;¡Ç{~:~t~jl lia. ~-- . "'°Q,rl ~~3 ,: ~ 'Wt J\~ " f" )~ ,~~ ~L/ (~~ -<21" . ìj\, :'~ II, 'iJ~ "'" ?~ \'.- ;. -v -'J ,,:+136 ' \ ' '\' 34 ..'::~ V~_ J ...,/WJ .', '" III ", ,,' ! '~_I..'~ r: I e;::;(~ _. Ii< . f ~ ç'~~O ,\),~ ~,~~ .', ~'" ~ ., 16 22 28 2r 6 34 r 36 4- 3 2 9 H) 11 10 8 1J 18 .. tn, '~ ~. '?<~~~ \,; " -- .' ~'--' 28 . ~~. '\ 1>.;>\/- ~ """" r'"'7 0. \'" ",8 ,\, 2' '\ì 16 -, r"\ '"". 1 " ../(~ '/I ð 136. _< 0'; J.t(' 136 33 {' ,.&t:: . II : .. -..,,~' ":::~.J "<. ~ .~...... £II . . \" ~~ )/"1 ~ ~ffr~::t!:7 - , ) " ". ':/ /( 'I . . ~ ~ Ç---' '" I 1_. ~ . A'~ Ì\~I~~-~ ,~ 16 C y ~ I, ....,. I , ". ! ":'1 ~ f::::;:7' ') ",,<lfr J '\ ,JJ'ð Ù~· l ~ 24'~' / ,- c.:..~ J "', \ 'fl ..' ~_ j' y. ./ I ) '~"I.) . 22 ____", . '\({i\ A _. ¿... '¡;\'~ . . / / 27 0 ..~.~ ",,¡.J &, '<",- ~) L! fl' 26 I~""'''''' ,,~ I:;ß,.L ~ ;;"'-"". . \ ".~ v . ., /" \ . _~~~~J. 33 '\f~ 34 I 36 < (~:"'J: ,~/ "" 36 /, " \j' ~!Î 31 / / ~ A \.< / ,,3 - ~ ? , >; r,...-,' - - )II ¡$ I ~. .' \ ~vv- ,,~~ 1\¡ß",f! ~' "" n 1L ;1~J "=" e .fl ;~u :þ J ~ 'oÄ 'v f) ~ ~ .. ~..}' íf ,;¿; i? ";/ 11 ~r 14 ,-- . : (~) -J~~ Afl f/ 13 r'JJ \,"~. ( r f~~~'\~ {/ /. 19 ~ 20 1&: k::::::;;'4 ~19 ~ r'ísl' "''' 111/ 23 i2~ \ ~. ~ ì\~~ I" ~ I( I.' (I:. ~ . "\\ '~)1 ~ -=' ~ '(:-í':: :~ I, Ii' ,; /~;¥:\,,, (J ~ I I' J ( ( 5 i:fj~' ;11\ \J 4 -. (./ _ ; J'/ ,,4;¡~ 30 31 6 ~ ·~.8'\ -:;~ '\I I 4 3 2 jp ¡ " ARCO Alaska, Inc. <> ' -"'~ o 2 MILES o 2 KILOMETERS Scale: 1" = 12,000' 6 EXHIB!T 14 pine Aquifer Exemption Area Colville River Unit 11-3-98 97062506D02 #1 e . ORIGINAL Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Colville River Unit Disposal Injection Order ARCO Alaska, Inc. by letter dated November 1, 1998 made application to the Commission for an order allowing the disposal injection of Class II fluids in the Alpine area of the Colville River Unit. A person who may be harmed if the requested order is issued may file a written protest prior to 400 PM, November 17, 1998, with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, and request a hearing on the matter. If the protest is timely filed and raises a substantial and material issue crucial to the Commission's determination, a hearing on the matter will be held at the above address concurrently with the Alpine Pool rules hearing scheduled for 9:00 AM on December 3, 1998, in conformance with 20 AAC 25.540. If a hearing is to be held, interested parties may confirm this by calling the Commission's office (907) 279-1433, after November 17, 1998. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 no later than November 23, 1998. ~ ----------- Published November 3, 1998 ADNA0029140 11 Search Results for Anchorage Daily News Classified Onlùitp://search.nando.netJplweb-cgi/...20AND%20%28LEGALS%29%3ACategory%20 e e . [ Anchorage Daily News I Today's Classifieds I Sunday's Classifieds ] Requested Classified Ad Copyright © 1997 Anchorage Daily News 1 of 1 1113/982:18 PM , f, b'I,O ~ DRI / MCGRAW HILL RANDALL NOTTINGHAM 24 HARTWELL LEXINGTON MA 02173 OVERSEAS SHIPHOLDING GRP ECON DEPT 1114 AV OF THE AMERICAS NEW YORK NY 10036 ALASKA OFC OF THE GOVERNOR JOHN KATZ STE 518 444 N CAPITOL NW WASHINGTON DC 20001 ARENT FOX KINTNER PLOTKIN KAHN LIBRARY WASHINGTON SQ BLDG 1050 CONNECTICUT AV NW WASHINGTON DC 20036-5339 LIBRARY OF CONGRESS STATE DOCUMENT SECTION EXCH & GIFT DIV 10 FIRST ST SE WASHINGTON DC 20540 ~~~,4d~10f'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 OIL DAILY CAMP WALSH 1401 NEW YORK AV NW STE 500 WASHINGTON DC 20005 US MIN MGMT SERV CHIEF OCS STATS & INFO 381 ELDEN ST MS 4022 HERNDON VA 20170-4817 U S DEPT OF ENERGY PHYLLIS MARTIN MS EI823 1000 INDEPENDENCE SW WASHINGTON DC 20585 , '. .. TECHSYS CORP BRANDY KERNS PO BOX 8485 GATHERS BURG MD 20898 DPC DANIEL DONKEL 1420 NORTH ATLANTIC AVE, STE 204 DAYTON BEACH FL 32118 AMOCO CORP 2002A LIBRARY/INFO CTR POBOX 87703 CHICAGO IL 60680-0703 LINDA HALL LIBRARY SERIALS DEPT 5109 CHERRY ST KANSAS CITY MO 64110-2498 MURPHY E&P CO ROBERT F SAWYER POBOX 61780 NEW ORLEANS LA 70161 e . .. US GEOL SURV LIBRARY NATIONAL CTR MS 950 RESTON VA 22092 SD DEPT OF ENV & NATRL RESOURCES OIL & GAS PROGRAM 2050 W MAIN STE #1 RAPID CITY SD 57702 ILLINOIS STATE GEOL SURV LIBRARY 469 NATURAL RESOURCES BLDG 615 E PEABODY DR CHAMPAIGN IL 61820 ALFRED JAMES III 107 N MARKET STE 1000 WICHITA KS 67202-1811 UNIV OF ARKANSAS SERIALS DEPT UNIV LIBRARIES FAYETTEVILLE AR 72701 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. 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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 EXXON EXPLOR CO LAND/REGULATORY AFFAIRS RM 301 POBOX 4778 HOUSTON TX 77210-4778 CHEVRON USA INC. ALASKA DIVISION ATTN: CORRY WOOLINGTON POBOX 1635 HOUSTON TX 77251 PHILLIPS PETR CO ALASKA LAND MGR POBOX 1967 HOUSTON TX 77251-1967 WORLD OIL MARK TEEL ENGR ED POBOX 2608 HOUSTON TX 77252 EXXON CO USA G T THERIOT RM 3052 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 ACE PETROLEUM COMPANY ANDREW C CLIFFORD PO BOX 79593 HOUSTON TX 77279-9593 PHILLIPS PETR CO JOE VOELKER 6330 W LP S RM 492 BELLAIRE TX 77401 TEXACO INC R EWING CLEMONS POBOX 430 BELLAIRE TX 77402-0430 e PENNZOIL E&P WILL D MCCROCKLIN POBOX 2967 HOUSTON TX 77252-2967 MARATHON MS. NORMA L. CALVERT POBOX 3128, STE 3915 HOUSTON TX 77253-3128 PHILLIPS PETR CO ERICH R. RAMP 6330 W LOOP SOUTH BELLAIRE TX 77401 PHILLIPS PETR CO PARTNERSHIP OPRNS JERRY MERONEK 6330 W LOOP S RM 1132 BELLAIRE TX 77401 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. 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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 e 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 . 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 . 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 BELLAIRE TX 77401 e 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 MAPLE WOOD 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 e ORO NEGRO, INC. 9321 MELVIN AVE NORTHRIDGE CA 91324-2410 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 AX 99501 e - US EPA REGION 10 LAURIE MANN OW-130 1200 SIXTH AVE SEATTLE WA 98101 PATTI SAUNDERS 1233 W 11TH AV ANCHORAGE AX 99501 DEPT OF ENVIRON CONSERV PIPELINE CORRIDOR REG OFC PAMELA GREFSRUD 411 W 4TH AVE ANCHORAGE AX 99501 DEPT OF REVENUE OIL & GAS AUDIT DENISE HAWES 550 W 7TH AV STE 570 ANCHORAGE AX 99501 GUESS & RUDD GEORGE LYLE 510 L ST, STE 700 ANCHORAGE AX 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 DEPT OF NATURAL RESOURCES DIV OIL & GAS WILLIAM VAN DYKE 3601 C ST STE 1380 ANCHORAGE AK 99503-5948 DEPT OF NATURAL RESOURCES DIV OF OIL & GAS 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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