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Home My WebLink AboutCO 311 BIndex Conservation Order 311B Pt McIntyre and West Beach Oil Pool 1. November 8, 1999 Arco Alaska's Pt McIntyre Application to Amend AI04B 2. November 20, 1999 Notice of Hearing and Affidavit of Publication 3. December 1, 1999 Ltr from AOGCC to Arco re: application 4. January 1, 2000 Meeting sign in sheet with Arco 5. January 13, 2000 Transcript of hearing, testimony, sign in sheet 6. March 9, 2000 Ltr from Arco answering questions from hearing 7. -------------- various e-mails re: application 8. May 23, 2007 Annual Surveillance Reporting Requirements (C0311 B.002) 9. February 20, 2020 BPXA's request for Amin Approval for Conforming PBU Greater Pt. McIntyre Area Satellite Pool Rules for Consistency (CO 31 IB -003) 10. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co311 B.004) 11. May 21, 2020 Notice of Hearing and mailing 12. ----------------- Emails . 1. 2. 3. 4. 5. 6. 7. 8. November 8, 1999 November 20, 1999 December 1, 1999 January 1, 2000 January 13, 2000 March 9, 2000 -------------- May 23,2007 . Index Conservation Order 311B Pt McIntyre and West Beach Oil Pool Arco Alaska's Pt McIntyre Application to Amend AI04B Notice of Hearing and Affidavit of Publication Ltr from AOGCC to Arco re: application Meeting sign in sheet with Arco Transcript of hearing, testimony, sign in sheet Ltr from Arco answering questions from hearing various e-mails re: application Annual Surveillance Reporting Requirements (C03llB.002) Conservation Order 311B .- .- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re: The application of ARCO Alaska, Inc. ) Conservation Order No. 311B ("AAI") to amend AIO 4B to initiate a ) Miscible Gas Enhanced Oil Recovery ) Prudhoe Bay Unit Project in the Point McIntyre Oil Pool ) West Beach Oil Pool and a Water and Gas Injection Enhanced ) Oil Project in the West Beach Oil Pool. ) April 19, 2000 IT APPEARING THAT: 1. By correspondence dated November 8, 1999, AAI requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to approve a waterflood enhanced oil recovery project in the West Beach Oil Pool. 2. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on November 20, 1999. 3. The Commission did not receive a protest or request for a public hearing. 4. The Commission held a hearing at the Commission's offices on January 12 and 13,2000. FINDINGS: 1. The Commission has issued Conservation Order No. 311 dated February 25, 1993 and Conservation Order No. 311A dated December 20, 1996 to govern development and depletion of the West Beach Oil Pool ("WBOP"). 2. The findings, conclusions and administrative records for the above listed Conservation Orders are incorporated by reference in this order. 3. The WBOP is estimated to contain 15 to 25 MMSTB of oil in place. 4. Recent WBOP reservoir simulation studies, incorporating all well and seismic data, indicated a peripheral waterflood could increase recovery over primary depletion by an incremental 10-15% of the OOIP, about 2 MMSTB. Gas injection to recover "attic" oil along the southern boundary fault is being evaluated and may be implemented in the future. 5. After production tests of wells WB-05B and WB-06, a peripheral waterflood will be implemented by converting either WB-04 or WB-06 to water injection. 6. Potential injectors, WB-04 and WB-06, have been drilled, cased, cemented and tested according to requirements of20 AAC 25.005. Applications and completion records are on file at the AOGCC. Whichever well is converted will be tested according to 20 AAC 25.412 prior to initiation of injection. 7. Facilities have been installed to accommodate additional production and injection wells if evaluation of field performance indicates additional reserves can be recovered. coo""vatioo Ocdec No. 31. . April 19, 2000 .- Page 2 8. The waterflood will be managed to replace reservoir voidage and injection rates will be modified in response to well performance. 9. The WBOP waterflood will utilize water produced from a dedicated source well drilled to the Tertiary Sagavanirktok Formation. Pump design capacity is expected to be 10,000 barrels per day. 10. No Sagavanirktok Formation water samples have been obtained from a West Beach pad well. Wire line log analyses of the West Beach State #1 well indicate Sagavanirktok Formation water samples from adjacent wells are representative of the interval in the West Beach Pad area. 11. Laboratory testing, core analyses and geochemical modeling indicate no significant problems are likely due to clay swelling or in-situ fluid compatibility problems between WBOP and Tertiary formation waters. 12. WBOP waterflood source water from the Sagavanirktok Formation is expected to have excess barium ion that could precipitate barium sulfate scale if mixed with PMOP produced water. WBOP produced water will be inhibited upstream of the commingling point with Pt. McIntyre Oil Pool fluids to prevent scale precipitation. 13. Estimated average and maximum injection pressures (at the pump discharge) for WBOP water injectors are 2100 and 2850 psi respectively. 14. Injection pressures are not likely to fracture the WBOP confining zones based on previous injection performance in similar stratigraphy in the adjacent PMOP. 15. Potential benefits of gas injection in WBOP are being studied. Preliminary evaluation of gas injection estimates maximum gas injection of25 MMSCFD with average and maximum injection pressures (at the pump discharge) of 4100 and 4500 psi respectively. No compatibility issues are anticipated between WBOP fluids and LPC residual gas. CONCLUSIONS: 1. It is appropriate to issue Conservation Order No. 311B consolidating Conservation Order No. 311 and Conservation Order No. 311A with rules to allow waterflood in the WBOP. 2. A waterflood in the WBOP will result in significant additional hydrocarbon recovery. 3. The WBOP water injection project will not cause waste, jeopardize correlative rights, or impair ultimate recovery. 4. A plan to inject gas in the WBOP is being evaluated and is not complete. 5. Reissuing Conservation Order No. 311B in its entirety and adding Rules 12 and 13 will maintain continuity in the administrative record and keep all orders affecting the WBOP in one Conservation Order. NOW, THEREFORE, IT IS ORDERED THAT (1) Conservation Order No. 311B supersedes Conservation Order No. 311 dated February 25, 1993 and Conservation Order No. 311A dated December 20, 1996. (2) The following rules, in addition to statewide requirements under 20 AAC 25, apply to the affected area described below: UMIAT MERIDIAN T12N, RISE Section 19 SYZ Section 20 SYZ Cons,,,,,';on Oeder No. 31' · April 19, 2000 .. Page 3 Section 21 SWIf¡ Section 28 NYz Section 29 NYz Section 30 NYz T12N, R14E Section 24 SYZ Section 25 NYz, SElf¡ Rule 1 Field and Pool Name The field is the Prudhoe Bay Field. Hydrocarbons contained within the Kuparuk River Formation constitute a single associated gas and oil reservoir called the West Beach Oil Pool. Rule 2 Pool Definition The West Beach Oil Pool is defined as the accumulation of oil and gas which is common to and correlates with the accumulation found in the West Beach No.4 well between the depths of 14,548' MD and 14,781' MD. Rule 3 Well 8pacine: Statewide 160-acre drilling units are in effect until such time as data or circumstances warrant the Commission to approve a change. Rule 4 Completion Practices Wells completed for production may utilize casing strings or liners cemented through the productive intervals and perforated slotted liners, screen-wrapped liners, gravel packs or open hole methods, or combinations thereof. Rule 5 Drilline: and Production Equipment Drilling and production equipment must meet the requirements of API RP 7G, Section 8, "Drillstem Corrosion and Sulfide Stress Cracking," Eighth Edition, April, 1978, or subsequent editions. Rule 6 Automatic Shut-in Equipment (a) Each well shall be equipped with a Commission approved fail-safe automatic surface safety valve system (SVS) capable of preventing uncontrolled flow by shutting off flow at the wellhead. ... (b) The SVS shall not be deactivated except during repairs, while engaged in active well work, or if \ the pad is manned. If the SVS cannot be returned to service within 24 hours, the well must be shut in at the wellhead and at the manifold building. 1. Wells with a deactivated SVS shall be identified by a sign on the wellhead stating that the SVS has been deactivated and the date it was deactivated. Conservation Order No.3 t .. April 19, 2000 .- Page 4 11. A list of wells with the SVS deactivated, the dates and reasons for deactivating, and the estimated reactivation dates must be maintained current and available for the Commission on request. ( c) A representative of the Commission will witness operation and performance tests at intervals and times as prescribed by the Commission to confirm that the SVS and all associated equipment are in proper working order. Rule 7 Common Facilities and Surface Commin2lin2 (a) Production from the West Beach Pool may be commingled on the surface with production from other pools prior to custody transfer. (b) Production from each pool will be determined by the following well test allocation method. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats. 1. Conduct well tests to determine production rates for each well. 11. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. 111. Sum the TMP volume for all wells in all pools. IV. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP). v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP X Allocation Factor (c) NGLs will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the Commission. (d) Each producing well will be tested at least twice each month. Wells that have been shut-in and cannot meet the twice-monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. (e) Optimum test duration and stabilization time will be determined on a well-by-well basis by the operator. (f) Water volumes will be determined by API/MPMS approved methods, or the use of industry proven on-line water cut measurement devices. (g) API gravity will be determined for each producing West Beach well monthly. (h) Gas samples will be taken for each non-gas lifted producing well yearly. (i) Quarterly allocation process reviews will be held with the Commission. (j) Prior to installing separate test facilities (if required by future development) at West Beach, Commission approval of the facilities must be obtained. (k) This rule may be revised or rewritten after an evaluation period of at least one year. Co",ervation Order No.3 t ,. April 19, 2000 .. Page 5 Rule 8 Production Anomalies In the event of a proration of oil production capacity at or from the LPC, all commingled fields produced at the LPC will be pro-rated by an equivalent percentage of oil production recognizing mechanical limitations and operational constraints. Rule 9 Reservoir Pressure Monitorint! (a) Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. (b) A minimum of one bottom-hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. (c) The datum for all surveys is 8,800' TVD SS. (d) Pressure survey will be a pressure buildup, pressure falloff, RFT, or static bottom-hole pressure after the well has been shut in for an extended period. (e) The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted on request. (f) Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part (e) of this rule. Rule 10 Development and Depletion Plan Within one year after start of regular production, the operator shall present to the Commission a more definitive development and depletion plan for this pool. Rule 11 Administrative Action Upon request by the operator or upon its own motion, the Commission may administratively amend this order if the revision does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Rule 12 West Beach Waterflood Proiect Water injection for additional oil recovery is approved for the West Beach Oil Pool. Rule 13 West Beach Oil Pool Annual Reservoir Report An annual West Beach Oil Pool surveillance report will be required by April 1 of each year. The report shall include but is not limited to the following: (a) Progress of the waterflood project implementation, progress on enhanced recovery evaluation and a reservoir management summary including engineering and geotechnical parameters. Conservation Order No. 31 It . April 19, 2000 .. Page 6 (b) Reservoir voidage balance by month of produced fluids and injected fluids. (c) Analysis of reservoir pressure surveys within the pool. (d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys and observation well data and surveys. (e) Results of any special monitoring. (f) Future development plans. (g) Review of Annual Plan of Operations and Development. DONE at Anchorage, Alaska and dated April 19, 2000. Robert N. Ch' nson, P.E., Chair Alaska Oil and Gas Conservation Commission ~~~ Cami1lé Oechsli Taylor, Commi lOner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice ofthe entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day if a holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An 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 dav after the aoolication for rehearing was filed). • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7 Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within ) Docket Number: CO -10 -21 existing Conservation Orders relating to ) Other Order No. 66 well safety valve systems. ) ) Statewide, Alaska ) January 11, 2011 IT APPEARING THAT: 1. On October 13, 2010 the Alaska Oil and Gas Conservation Commission ( AOGCC or Commission) formally adopted new regulations relating to well safety valve systems, at 20 AAC 25.265. 2. The newly adopted well safety valve system regulations underwent final review by the Regulations Section of the Alaska Attorney General's Office and were forwarded to the Alaska Lieutenant Governor's Office on October 28, 2010. 3. The new regulations were signed by the Lieutenant Governor and took legal effect on December 3, 2010. 4. To ensure consistency with the new regulations, the AOGCC, on its own motion, proposed to rescind part or all of the outdated rules within existing Commission Orders relating to well safety valve systems. 5. On November 4, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Daily News notice of opportunity for public hearing on December 6, 2010. 6. The Commission received written comments in response to its public notice, and held a public hearing on December 7, 2010. 7. Oral testimony and written comments were provided at the December 7, 2010 hearing. FINDINGS: 1. Well safety valve systems are regulated under newly- adopted 20 AAC 25.265, which consolidates the requirements previously established in legacy documents, policies, and statewide guidelines relating to safety valve systems. 2. Thirty -four existing Commission Orders contain rules governing well safety valve systems. Twenty of those Orders contain broad regulatory requirements for safety valve systems that are now covered by the newly- adopted regulations. The remaining fourteen Orders include field- or pool - specific safety valve system requirements. . . Other Order 66 • • Page 2 Statewide, AK January 11, 2011 3. Within existing Commission Orders are rules unrelated to well safety valve systems; these rules will continue in effect, unmodified. 4. Existing Commission Orders containing individual rules relating to well safety valve systems are enumerated in the attached Table. CONCLUSIONS: 1. Eliminating redundant requirements and standardizing wording for those field - and pool - specific safety valve system requirements deemed appropriate to retain will improve regulatory clarity. 2. Twenty existing Commission Orders that include rules relating to well safety valve systems are rendered unnecessary, and can be replaced by newly- adopted 20 AAC 25.265. As more fully set forth in the attached Table, those Orders are Conservation Orders 98A, 207A, 300, 311B, 317B, 329A, 341E, 345, 402B, 432D, 452, 457B, 471, 477, 484A, 505B, 553, 559, 570, and a Commission unnumbered Order signed March 30, 1994 (policy dictating SVS performance testing requirements). 3. Fourteen existing Commission Orders include field- or pool- specific safety valve system requirements that the Commission considers appropriate for retention. Wording for the same safety valve system requirements existing in different Commission Orders has been standardized. As more fully set forth in the attached Table, those Orders are Conservation Orders 406B, 423, 430A, 435A, 443B, 449, 456A, 458A, 562, 563, 569, 596, 597, and 605. NOW, THEREFORE, IT IS ORDERED THAT individual rules in thirty-four existing Commission Orders that relate to well safety valve systems are hereby rescinded or revised as enumerated in the Table. Remaining rules unrelated to safety valve systems within affected Commission Orders remain in effect, unmodified. DONE at Anchorage, Alaska, and dated ary 11, 2011 Apiee Daniel T. Se. r ou , r., Commissioner, Chair . • it . a ss Conservation Commission I � � rman, Co ' nner o Oi , . i a Conserva ion Commission �i * ; . • .1 •1 , Cat y P. toerst-r, Commissioner r r " v colAr Alaska • it and Gas Conservation Commission • Other Order 66 • • Page 3 Statewide, AK January 11, 2011 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after l the Commission otherwise distributes, the order or decision denying the date on which the Commission mails, OR 30 days if t e Com ss�o 0 Y Y g reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(6), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. • Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 2011 4:08 PM To: Ballantine, Tab A (LAW); '(foms2 @mtaonline.net)'; '( michael .j.nelson @conocophillips.com)'; '(Von.L .Hutchins @conocophillips.com)'; 'AKDCWellIntegrityCoordinator; 'Alan Dennis'; 'alaska @petrocalc.com'; 'Anna Raff; 'Barbara F Fullmer; 'bbritch'; 'Becky Bohrer; 'Bill Penrose'; 'Bill Walker; 'Bowen Roberts'; 'Brad McKim'; 'Brady, Jerry L'; 'Brandon Gagnon'; 'Brandow, Cande (ASRC Energy Services)'; 'Brian Havelock'; 'Bruce Webb'; 'carol smyth'; 'caunderwood'; 'Chris Gay; 'Cliff Posey'; 'Crandall, Krissell'; 'D Lawrence'; 'dapa'; 'Daryl J. Kleppin'; 'Dave Matthews'; 'David Boelens'; 'David House'; 'David Steingreaber'; 'ddonkel @cfl.rr.com'; 'Deborah J. Jones'; Delbridge, Rena E (LAA); 'Dennis Steffy'; 'Elowe, Kristin'; 'Erika Denman'; 'eyancy'; 'Francis S. Sommer; 'Fred Steece'; 'Gary Laughlin'; 'Gary Rogers'; 'Gary Schultz'; 'ghammons'; 'Gordon Pospisil'; 'Gorney, David L.'; 'Greg Duggin'; 'Gregg Nady'; 'gspfoff; 'Harry Engel'; 'Jdarlington (jarlington @gmail.com)'; 'Jeanne McPherren'; 'Jeff Jones'; 'Jerry McCutcheon'; 'Jill Womack'; 'Jim White'; 'Jim Winegarner; 'Joe Nicks'; 'John Garing'; 'John Katz'; 'John S. Haworth'; 'John Spain'; 'John Tower; 'Jon Goltz'; 'Judy Stanek'; 'Julie Houle'; 'Kari Moriarty'; 'Kaynell Zeman'; 'Keith Wiles'; 'Kelly Sperback'; 'Kim Cunningham'; 'Larry Ostrovsky'; 'Laura Silliphant'; 'Marilyn Crockett'; 'Mark Dalton'; 'Mark Hanley (mark.hanley @anadarko.com)'; 'Mark Kovac'; 'Mark P. Worcester; 'Marguerite kremer; 'Michael Dammeyer; 'Michael Jacobs'; 'Mike Bill'; 'Mike Mason'; 'Mikel Schultz'; 'Mindy Lewis'; 'MJ Loveland'; 'mjnelson'; 'mkm7200'; 'nelson'; 'Nick W. Glover'; 'NSK Problem Well Supv'; 'Patty Alfaro'; 'Paul Decker (paul.decker @alaska.gov)'; 'Paul Figel'; 'PORHOLA, STAN T'; 'Randall Kanady'; 'Randy L. Skillern'; ' rob.g.dragnich @exxonmobil.com'; 'Robert Brelsford'; 'Robert Campbell'; 'Ryan Tunseth'; 'Scott Cranswick'; 'Scott Griffith'; Scott, David (LAA); 'Shannon Donnelly'; 'Sharmaine Copeland'; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); 'Sondra Stewman'; 'Steve Lambert'; 'Steve Moothart'; 'Steven R. Rossberg'; 'Suzanne Gibson'; 'tablerk'; 'Tamera Sheffield'; Taylor, Cammy 0 (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjrl'; 'Valenzuela, Mariam '; 'Vicki Irwin'; 'Walter Featherly'; 'Will Chinn'; Williamson, Mary J (DNR); 'Yereth Rosen'; 'Aaron Gluzman'; Bettis, Patricia K (DNR); caunderwood @marathonoil.com; 'Dale Hoffman'; 'David Lenig'; 'Gary Orr'; 'Jason Bergerson'; 'Joe Longo'; 'Lara Coates'; 'Marc Kuck'; 'Mary Aschoff; 'Matt Gill'; 'Maurizio Grandi'; Ostrovsky, Larry Z (DNR); 'Richard Garrard'; 'Sandra Lemke'; 'Talib Syed'; 'Tiffany Stebbins'; 'Wayne Wooster; 'William Van Dyke'; Woolf, Wendy C (DNR); Aubert, Winton G (DOA) (winton.aubert@alaska.gov); Brooks, Phoebe L (DOA) (phoebe.brooks @alaska.gov); Colombie, Jody J (DOA) (jody.colombie @alaska.gov); Crisp, John H (DOA) (john.crisp @alaska.gov); Davies, Stephen F (DOA) (steve.davies @alaska.gov); Foerster, Catherine P (DOA) (cathy.foerster @ alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi @alaska.gov); Johnson, Elaine M (DOA) (elaine.johnson @ alaska.gov); Jones, Jeffery B (DOA) (jeff.jones @alaska.gov); Laasch, Linda K (DOA) (linda.laasch @alaska.gov); Maunder, Thomas E (DOA) (tom.maunder @alaska.gov); McIver, Bren (DOA) (bren.mciver @alaska.gov); McMains, Stephen E (DOA) (steve.mcmains @alaska.gov); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA) (bob.noble @alaska.gov); Norman, John K (DOA) (john.norman @alaska.gov); Okland, Howard D (DOA) (howard.okland @alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk @alaska.gov); Pasqual, Maria (DOA) (maria.pasqual @alaska.gov); Regg, James B (DOA) (jim.regg @alaska.gov); Roby, David S (DOA) (dave.roby @alaska.gov); Saltmarsh, Arthur C (DOA) (art.saltmarsh @alaska.gov); Scheve, Charles M (DOA) (chuck.scheve @alaska.gov); Schwartz, Guy L (DOA) (guy.schwartz @alaska.gov); Seamount, Dan T (DOA) (dan.seamount @alaska.gov); Shartzer, Christine R (DOA) Subject: Other 66 Safety Valve Systems Attachments: other66.pdf Sa acw,th v FIB Y K 4 Aiwa-Ica/ OW aw C Co -viwva.t o v Co-win (907)793 -1223 (907)276 -7542 (ft.) 1 • 1 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group George Vaught, Jr. Cartography GEPS P.O. Box 13557 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Denver, CO 80201 -3557 Ft. Worth, TX 76102 -6298 Houston, TX 77056 1 Jerry Hodgden Richard Neahring Mark Wedman Hodgden Oil Company NRG Associates Halliburton 408 18 Street President 6900 Arctic Blvd. Golden, CO 80401 -2433 P.O. Box 1655 Anchorage, AK 99502 Colorado Springs, CO 80901 Bernie Karl CIRI Baker Oil Tools K &K Recycling Inc. Land Department 795 E. 94 Ct. P.O. Box 58055 P.O. Box 93330 Anchorage, AK 99515 -4295 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider Gordon Severson P.O. Box 69 US Geological Survey 3201 Westmar Circle Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 -4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs P.O. Box 190083 P.O. Box 39309 P.O. Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Cliff Burglin Refuge Manager 399 West Riverview Avenue 319 Charles Street P.O. Box 2139 Soldotna, AK 99669 -7714 Fairbanks, AK 99701 Soldotna, AK 99669 -2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 O 4°' \ \`' , v Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Reqts from Order Revised Rule - "Well safety valve systems" (2) Comment fail -safe auto SSV and SCSSV; injection wells (except disposal) require "I wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "Injection wells (excluding disposal injectors) must be with(i) a double valve 25.265(a); 25.2659(b); 25.265(d)(1); e equipped oue check Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Nuiqsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); 25.265(b); 25.265(d)(1); "Injection wells (excludin disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit Raven 570 5 yes N/ deactivated SVS was replaced with requirement to maintain a deactivated SVS; sign wellhead 2 5.265 m g ( ) tag on well when not manned fail -safe auto SSV and SCSSV; injection wells (except disposal) require 25.265(a); "I nject i on we ll s (exc disposal injectors) must be equipped with(i) a double check valve (a); 25 25 Check valve requirements for injectors are not covered by Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "I wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV and SCSSV; injection wells (except disposal) require "I wells (excluding disposal injectors) must be equipped with(i) a double check valve 25.265(a); 25.265(b); 25.265(d)(2)(H); Check valve requirements for injectors are not covered by Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection . arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or 25.265(h)(5) readopted regulation valve satisfies single check valve requirement; test every 6 months ( )( 5 ) SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Put River 559 3 yes prescribed by Commission 25.265(h)(5) pp requirement aces SSSV nipple re uirement for all wells Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV , 25.265(a) N/A Prudhoe Ba Unit Orion 505B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y prescribed by Commission 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Polaris 484A 3 yes prescribed by Commission 25.265(h)(5) p nipple requirement laces SSSV ni le re uirement for all wells fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI Milne Point - 25.265(a); 25.265(b); 25.265(d); Readopted 25.265(d) dictates which wells require SSSV; Milne Point Unit 477 5 yes injection well require SSSV or injection valve below permafrost; test N/A Schrader Bluff every 6 months 25.26 5( h )( 5 ) replaces SSSV nipple requirement for all wells p laces pp re q Prudhoe Ba Unit Borealis 471 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; gas /MI 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y Y injection wen require SSSV below permafrost; test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; test as prescribed by Commission; 500• 25.265(a); 25.265 b 25.265(d)(1) g g y y Existing pool rule established a minimum setting depth for the Northstar Northstar 458A 4 no ft minimum setting depth for SSSV ( ); " The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." SSSV Prudhoe Ba Unit Aurora 457B 3 yes fail -safe auto SSV; SSSV landing nipple below permafrost; test every 6 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Y Y months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV; gas /MI injectors require SSV and single check "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by 25.265(a); 25.265(b); 25.265(d); Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include 25.265(h)(5) check valve, or (ii) single check valve and SSV; test every 6 months SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Prudhoe Bay Unit Midnight Sun 452 6 yes fail -safe auto SSV (all injectors and producers capable of unassisted 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; flow to surface); test every 6 months 25.265(h)(5) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be installed above or below 25.265(a); 25.265(b); 25.265(d)(1); The setting depth of a required subsurface safety valve must be located in the tubing either Existing pool rule established alternate SSSV setting depth; Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LPS trip above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by pressure; test every 6 months 25 arrangement." readopted regulation fail -safe auto SSV and SCSSV (producers and gas injectors); water "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve 25.265(a); 25.265(b); 25.265(d)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface - controlled injection valve or readopted regulation and SSV SCSSV satisfies the requirements of a single check valve." fail -safe auto SSV; gas /MI injectors require SSV and single check 25.263(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double r arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS Requirement to maintain a wellhead sign and list of wells with deactivated; maintain list of wells w /deactivated SVS; test as deactivated SVS was replaced with requirement to maintain a Kuparuk River Unit; 25.265(a); 25.265(b); 25.265(h)(5); Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP N/A tag on well when not manned; administrative approval CO Milne Point Unit 25 m ( ) may be defeated on W. Sak injectors w /surface pressure <500psi w/ 432D.009 remains effective [re:defeating the LPS when surface notice when defeated and placed back in service injection pressure for West Sak water injector is <500psi] Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Conservation New Regulation Provisions Revised Rule - "Well safety valves stems' (2) Comment Unit/Field Pool Order (1) Rule Rescind Rule? Existing Order Requirement Addressing Regts from Order y systems" fail -safe auto SSV; gas /MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Check valve requirements for injectors are not covered by Kuparuk River Unit Tarn 430A 6 no valve and SSSV landing nipple; water injection wells require (i) double arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include check valve, or (ii) single check valve and SSV; test every 6 months 25 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Milne Point - Sag 423 7 no fail -safe auto SSV; injection wells require double check valve; test j Check valve requirements for injectors are not covered by Milne Point Unit every 6 months 25.265(a); a ) ; 25.265 ( b ) 25.265(h)(5) h )( 5 ) "Injection wells must be equipped with a double check valve arrangement " readopted regulation River fail -safe auto SSV; gas /MI injectors require SSV and single check Check valve requirements for injectors are not covered by valve and SSSV landing nipple; water injection wells require (i) double "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve readopted regulation; readopted 25.265(d)(5) does not include Kuparuk River Unit Kuparuk - West Sak 406B 6 no check valve or (ii) single check valve and SSV; test every 6 months; 25.265(2); 25.265(b); 25.265(d); arrangement or (ii) a single check valve and a SSV. A subsurface-controlled injection valve or SSSV requirement for MI injectors; administrative approval CO p p CO 406B.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be 4068.001 remains effective (re:defeating the LPS when surface injectors w /surface pressure <500psi w/ notice when defeated and defeated on West Sak water injectors with surface injection pressure less than 500psi " injection pressure for West Sak water injector is <500psi] placed back in service fail -safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 402B 6 yes control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b); 25.265(h); N/A submit test results electronically within 14days; SVS defeated /removed 25.265(m) only if well SI or pad continuously manned fail -safe auto SSV (S /D well and artificial lift); sign on well if SVS 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with Prudhoe Bay Unit North Prudhoe 345 4 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a prescribed by Commission tag on well when not manned fail -safe auto SSV (S /D well and artificial lift); if SSSV installed it must be maintained and tested as part of SVS; sign on well if SVS 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Prudhoe 341E 5 yes deactivated; maintain list of wells w /deactivated SVS; test as 25.265(h)(5) replaces SSSV nipple requirement for all wells prescribed by Commission fail -safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Niakuk 329A 5 yes deactivated SVS; sign on wellhead 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV and SCSSV; SSSV may be rermoved as part of 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit Pt. McIntyre 317B 8 yes routine well ops w/o notice 25.265(1); 25.265(m) replaces SSSV nipple requirement for all wells fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; Prudhoe Bay Unit West Beach 311B 6 yes w /deactivated SVS; test as prescribed by Commission 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells West Fork West Fork (Sterling 300 5 yes fail -safe auto SVS on each production tubing 25.265(a); 25.265(b) N/A A &B) fail -safe auto SSV; sign on well if SVS deactivated; maintain list of wells 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with N/A deactivated SVS was replaced with requirement to maintain a Prudhoe Bay Unit Lisburne 207A 7 yes w /deactivated SVS; test as prescribed by Commission 25.265(m) tag on well when not manned suitable automatic safety valve installed below base of permafrost to N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265 d Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes prevent uncontrolled flow 25.265(d) ) replaces SSSV nipple requirement for all wells AOGCC Policy - SVS Failures; issued by order of the Commission policy dictating SVS performance testing Statewide N/A N/A N/A yes 25.265(h); 25.265(n); 25.265(o) N/A Commission 3/30/1994 (signed by Commission Chairman requirements Dave Johnson) Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N /A" means entire pool rule to be rescinded Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 . I'M n LTul1 . (ill \ 0lnl \ ci2) ~ FRANK H. MURKOWSKI. GOVERNOR AI,ASIiA. ORAND GAS CONSERVATION COMMISSION 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAJ< (907)276-7542 ADMINISTRATIVE APPROVAL NO. 207.17 ADMINISTRATIVE APPROVAL NO. 311B.Ol ADMINISTRATIVE APPROVAL NO. 329A.Ol ADMINISTRATIVE APPROVAL NO. 3410.01 ADMINISTRATIVE APPROVAL NO.345.01 ADMINISTRATIVE APPROVAL NO. 452.01 ADMINISTRATIVE APPROVAL NO. 457A.Ol ADMINISTRATIVE APPROVAL NO. 471.01 ADMINISTRATIVE APPROVAL NO. 484.01 George Blankenship GPB Field Manager BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, Alaska 99519 Dear Mr. Blankenship: Conservation Order No. 492, dated June 26, 2003, amended the conservation orders adopting pool rules for all pools within the Prudhoe Bay field to add rules addressing sustained annulus pressures in devel- opment wells. Upon further review, the Commission has determined that paragraph 6 of these annulus pressure rules should be clarified. Paragraph 6 provides that before a shut-in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree that specified annulus pressures at operating temperature will not be reached or exceeded. However, paragraph 3 of the annulus pressure rules contemplates that there may be wells that can be safely operated with an annu- lus pressure in excess of a maximum specified in paragraph 6, and in such cases it would not be practicable or meaning- ful to relieve annulus pressure to the degree required under paragraph 3 when placing a shut-in well in service. In addi- tion, the Commission may approve different pressure limits for well start-up on a case-by-case basis under paragraphs 4 and 5. c:c-¡ l.\lií\\L.:\". rVJ!":.: n l!l 'j[lO') ~~ ð~!~' ~¡;;~ ~.\ 't,1,J Ð (~J.J . . July 29, 2003 Page 2 of2 Accordingly, Conservation Orders No. 207, 311B, 329A, 341D, 345, 452, 457A, 471, and 484 are amended to replace paragraph 6 of the annulus pressure rules adopted in Conservation Order No. 492 with the following revised paragraph 6: 6. Except as otherwise approved by the AOGCC under para- graph 4 or 5 of these rules, before a shut-in well is placed in service, any annulus pressure must be relieved to a suffi- cient degree (a) that the inner annulus pressure at operating temperature will be below 2500 psig for wells processed through the Lisburne Production Center and below 2000 psig for all other development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. DATED at Anchorage, Alaska and dated July 29, 2003. ~, '¡;".- BY ORDER OF THE COMMISSION . ~ 1r ffil1r Œ (ill ~ ffil ~ ffil ~ [{ ffil . AIIA~1iA. OIL A1Q) 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 NO. 311B.002 Mr. Mark C. Weggeland GPMA Resource Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Weggeland: The Alaska Oil and Gas Conservation Commission ("Commission") is amending the reporting dates of Rule 13 West Beach Oil Pool Annual Reservoir Report of Conservation Order 311B - Prudhoe Bay Unit, West Beach Oil Pool. The change is necessary so that the rule is not contradictory to the schedule agreed upon by the Commission and BP Exploration (Alaska) Inc. Rule 13 West Beach Oil Pool Annual Reservoir Report is amended to read as follows (additions are in bold and [deletions are bracketed]): Rule 13 West Beach Oil Pool Annual Reservoir Report An annual West Beach Oil Pool surveillance report will be required on a schedule agreed upon by the Commission and the operator[by April 1 of each year]. The report shall include but is not limited to the following: (a) Progress of the waterflood project implementation, progress on enhanced recovery evaluation and a reservoir management summary including engineering and geotechnical parameters. (b)Reservoir voidage balance by month of produced fluids and injected fluids. (c) Analysis of reservoir pressure surveys within the pool. (d) Results and, where appropriate, analysis of production and injection log surveys, tracer surveys and observation well data and surveys. (e) Results of any special monitoring. CO 311B.002 May 23,2007 Page 2 of2 . . (f) Future development plans. (g) Review of Annual Plan of Operations and Development. 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. orage, Alaska and dated May 23,2007. ~ Daniel T. Seamount, Jr. Commissioner Cathy P. Foerster Commissioner 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, W A 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 ~ SJ Various Administrative Approvals for North. . Subject: Various Administrative Approvals for North Slope From: Jody Colombie <jody_colombie@admin.state.ak.us> Date: Thu, 24 May 2007 06:39:39 -0800 To: undisclosed-recipients:; BCC: Cynthia B Mciver <bren_mciver@admin.state.ak.us>, Christine Hansen <c.hansen io .s ok.us>, Terrie Hubble <hubblet1@bp.com>, Sondra Stewman <StewmaS .com>, stanekj <stanekj@unocal.com>, r1@aol.com>,jdarlington <jdarlington@forestoil.com>, n on <knelson@petroleu , Mark Dalton <mark.dalton@hdrinc.com>, Sh n Donnelly <shannon. do onocophillips.com>, "Mark P. Worcester" <mark.p.worcester cophillips.com>, Bob <bo etkeeper.org>, tjr <tjr@dnr.state.ak.us>, bbritch <bbritch@alaska.net>, mjnelson <mjnelson@purvingertz.com>, Charles O'Donnell <charles.o'donnell@veco.com>, "Randy L. Skillern" <SkilleRL@BP.com>, "Deborah J. Jones" <JonesD6@BP.com>, "Steven R. Rossberg" <RossbeRS@BP.com>, Lois <lois@inletkeeper.org>, Dan Bross <kuacnews@kuac.org>, Gordon Pospisil <PospisG@BP.com>, "Francis S. So '<SommerFS@BP.com>, Mikel Schultz <Mikel.Schultz@BP.com>, "Nick W. Glover" <GloverNW@BP.com>, "Daryl J. Kleppin" <KleppiDE@BP.com>, "Janet D. Platt" <PlattJD@BP.com>, "Rosanne M. Jacobsen" <JacobsRM@BP.com>, ddonkel <d el@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.f.fullmer@conocophillips. >, doug_schultze <doug_schultze@xtoenergy.com>, H lford <hank.alford@exxonmobil.com>, Mark Kovac <yesno l@gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg N ady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us>, rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@a1aska.net>" eyancy <eyancy@sea1-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <b1@mapa1aska.com>, jah <jah@dnr.state.ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_han1ey@anadarko.com>, Julie Houle <ju1ie_hou1e@dnr.state.ak.us>, John W Katz <jwkatz@a1askadc.org>, tab1erk <tablerk@unocal.com>, Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us>, im White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmo . .com>, marty <m rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@ alaska. net>, 00 <mkm7200@aol.com>, Brian Gille uaa.alaska.edu>, David L Boelens <dboele urorapower.com>, Todd Durkee <to . urkee anadarko. com>, Gary Schultz <gary_schultz@dnr.state.ak.us>, Wayne Rancier <RANCIER@petro-canada.ca>, Brandon Gagnon <bgagnon@brenalaw.com>, Paul Winslow <pmwinslow@forestoil.com>, Sharmaine Copeland <copelasv@bp.com>, Kristin Dirks <kristin_dirks@dnr.state.ak.us>, Kaynell Zeman <kjzeman@marathonoil.com>, John Tower <John.Tower@eia.doe.gov>, Bill Fowler <Bill_Fowler@anadarko.COM>, Scott Cranswick <scott.cranswick@mms.gov>, Brad McKim <mckimbs@BP.com>, James Scherr <james.scherr@mms.gov>, Tim Lawlor <Tim_Lawlor@ak.blm.gov>, Lynnda Kahn <Lynnda_K @ v>, Jerry Dethlefs <Jerry.C.Dethlefs@conocophillips.com>, crockett@aoga.org, Tamera S ld < effield@aoga.org>, Jon Goltz <Jon.Goltz@conocophillips.com>, Roger Belman <roger.bel conocophillips.com>, Mindy Lewis <mlewis@brenalaw.com>, Kari Moriarty <moriarty@aoga.org>, Patty Alfaro <palfaro@yahoo.com>" Gary Rogers <gary _rogers@revenue.state.ak.us>, Arthur Copoulos <Arthur _ Copoulos@dnr.state.ak.us>, Ken <klyons@otsintl.com>, Steve Lambert <salambert@unocal.com>, Joe Nicks <news@radiokenai.com>, Jerry McCutcheon <susitnahydronow@yahoo.com>, Bill Walker <bill-wwa@ak.net>, Paul Decker <paul_decker@dnr.state.ak.us>, Aleutians East Borough <admin@aleutianseast.org>, Marquerite kremer <marguerite_kremer@dnr.state.ak.us>, Mike Mason <mike@kbbi.org>, Garland Robinson <gbrobinson@marathonoil.com>, Cammy Taylor <cammy_taylor@dnr. .ak.us>, Thomas E Maun tomßaunder@admin.state.ak.us>, Stephen F Davies <stev vies@admin.state.ak.us>, Keith lles <kwiles@marathonoil.com>, Deanna Gamble <dgamble@ akivik.com>, James B Regg 10f3 5/24/2007 6:40 AM Various Administrative Approvals for North. . <jim Jegg@admin.state.ak.us>, Cather' oerster <cathy _foerster@admin.stat k.us>, gregory micallef <micallef@clearwire.net>, La liphant <laura_silliphant@dnr.state. . s>, David Steingreaber <david.e.steingreaber bil.com>, akpratts@acsalaska.net, Robert Campbell <Robert.Campbell@reuters.com>, Stev thart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowjones.com>, Cliff Posey <cliff@posey.org>" Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.ak.us>, Walter Featherly <WFeatherly@PattonBoggs.com>, Tricia Wag twaggoner@nrginc.com>, John Spain <jps@stateside.com>, Cody Rice < _Rice@legis.stat >, John Garing <garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Ji inegamer <jimwinegamer@brooksrangepetro.com>, Matt Rader <matt_rader@dnr.state.ak.us>, carol smyth <carol. shell. com>, Arthur C Saltmarsh <art_saltmarsh@admin.state.ak.us>, Chris Gay <cdgay@m . .com>, foms@mtaonline.net, Rudy Brueggeman <rudy.brueggemann@international.gc.ca>, Cary CarrIgan <cary@kfqd.com>, Sonja Frankllin <sfranklin6@bloomberg.net>, Mike Bill <Michael.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan_birnbaum\"@law.state.ak.us>, Randall Kanady <Randall.B.Kanady@conocophillips.com>, MJ Loveland <N1878@conocophillips.com>, Dave Roby <dave_roby@admin.state.ak.us>, James B Regg <jim _regg@admin.state.ak.us> Jody Colombie <jody colombieC2l}admin.state.ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration Content-Type: applicationJpdf AI04E-22.pdf Content-Encoding: base64 C0311B-002.p ent- Type: applicationJpdf tent-Encoding: base64 Content-Type: applicationJpdf C0570-002.pdf . Content-Encodmg: base64 Content-Type: applicationJpdf C0471-006.pdf Content-Encoding: base64 Content-Type: applicationJpdf C0484A-001.pdf . Content-Encodmg: base64 2of3 5/24/20076:40 AM Various Administrative Approvals for North. . Content-Type: applicationJpdf C0457B-002.pdf Content-Encoding: base64 Content- Type: applicationJpdf C0317B-002.pdf Content-Encoding: base64 30f3 5/24/2007 6:40 AM THE STATF 01ALASKA GOVERNORMICHAEL I. DUNLr_AVY Ms. Katrina Garner Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL CONSERVATION ORDER NO. 207D.001 CONSERVATION ORDER NO. 311B.003 CONSERVATION ORDER NO. 317B.003 CONSERVATION ORDER NO. 329B.005 CONSERVATION ORDER NO. 345.002 CONSERVATION ORDER NO. 362A.006 CONSERVATION ORDER NO. 570.010 PBU Area Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -20-003 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov Request for Administrative Approval for Conforming Prudhoe Bay Unit (PBU) Greater Point McIntyre Area Satellite Pool Rules for Consistency Prudhoe Bay Unit Lisburne Oil Pool — Conservation Order (CO) 207D West Beach Oil Pool — CO 311B Pt. McIntyre and Stump Island Oil Pools — CO 317B Niakuk Oil Pool — CO 329B North Prudhoe Bay Oil Pool — CO 345 Greater Point McIntyre Area — CO 362A Raven Oil Pool — CO 570 Dear Ms. Garner: By letter dated February 20, 2020, BP Exploration (Alaska) Inc. (BPXA) requested administrative approval to amend the pool rules in the above referenced orders to bring conformity and consistency to the rules governing operations in the pools in the Greater Point McIntyre Area (GPMA), to make operations more efficient, and to make compliance oversight for the Alaska Oil and Gas Conservation Commission (AOGCC) simpler. There are several requests that apply broadly across multiple GPMA pools. These are as follows. COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page 2 of 12 Well Spacing Requirements: Currently, the Lisburne Oil Pool (LOP) has an interwell spacing requirement of one well per government quarter section and no pay opened within 1,000 feet of another well. The West Beach Oil Pool (WBOP) has an interwell spacing requirement of one well per 160 acres until circumstances warrant the AOGCC changing it. The Pt. McIntyre Oil Pool (PMOP) has a spacing requirement of one well per 40 acres with no pay open within 500 feet of another well. The Niakuk Oil Pool (NOP) gives the AOGCC the authority to approve the drilling of any well that is at least 500 feet from the affected area boundary and does not have open pay within 1,000 feet of another well. The Raven Oil Pool (ROP) has an interwell spacing requirement of 20 acres with no pay open within 500 feet of the affected area external boundary. BPXA requests that the interwell spacing requirements be eliminated and that the only spacing requirement be a 500 -foot offset from property lines where the landowner is not the same on both sides of the line. At the time the spacing requirements in these pool rules were imposed wells were being drilled nearly vertically. Because modern horizontal and multi -lateral wells are now being utilized to develop pools, BPXA needs flexibility to drill wells as dictated by the geology and reservoir models in order to maximize recovery. Standardizing the spacing requirements by eliminating interwell spacing requirements while retaining property offset requirements will result in improved recovery while protecting correlative rights. Pressure Survey Requirements: BPXA requests that the pressure survey requirements be modified so that compliance with regulatory oversight becomes simpler and data is collected in a meaningful manner. Currently, the Lisburne Oil Pool (LOP) requires at least one pressure survey be taken each year from each producing drillsite and that the results be submitted monthly, while the West Beach Oil Pool (WBOP), Pt. McIntyre Oil Pool (PMOP), and Niakuk Oil Pool (NOP) require one pressure survey per producing governmental section per year and results submitted quarterly. North Prudhoe Bay Oil Pool (NPBOP) requires one pressure survey per producing governmental section but doesn't specify when the results need to be reported, and Raven Oil Pool (ROP) requires one pressure survey per reservoir compartment where production wells exist and specifies the results are to be reported in the annual reservoir surveillance report. The inconsistency in where pressure surveys need to be collected and how the results are to be reported makes it more difficult for the operator to stay in compliance without yielding any benefit that could not be obtained by more uniform collection and reporting requirements. Moreover, after decades of development and reporting, the pools in the PBU are well understood and have sophisticated reservoir models. At this point, monitoring of reservoir pressure is important for proper reservoir development and targeted pressure surveys would provide the most useful information for reservoir development purposes. Presenting the results of the reservoir pressure surveys from the prior year in the annual reservoir surveillance report and proposing a plan for collection of reservoir pressure surveys in the coming year as part of the annual reservoir surveillance report will give the AOGCC an opportunity to review the data and ensure the proposed plans are adequate. This is consistent with how the other pools in the PBU are managed. COs 207D.001, 31113.003, 31713.003, 32913.005, 345.002,362A.006,570.010 April 3, 2020 Page 3 of 12 Well Testing: The GPMA pools have inconsistent well testing requirements that include quarterly allocation process reviews, monthly allocation reports, determining water volumes by API approved methods or an on-line water cut meter, monthly or annual API gravities for each well depending on the pool, gas samples collected yearly from each non -gas lifted producer, a minimum of two well tests per well, and twice monthly well tests. BPXA requests to eliminate the quarterly allocation process reviews and monthly allocation reports and proposes instead to provide an allocation factor report as part of the annual surveillance report as is done elsewhere in the PBU. BPXA also requests eliminating the water volume calculation, API gravity, and gas sampling requirements since at this point, recovery methods in these pools are unchanging and render this data of little benefit. Finally, BPXA requests to eliminate the requirement to test each producing well at least twice each month and instead require a minimum of one test per month per well. This request is consistent with how the rest of the PBU is managed and allows BPXA to maximize its well testing resources by testing the wells with stable production less frequently and testing the wells with less stable production more frequently to improve the overall allocation of production. Additionally, BPXA makes several requests that apply only to a single pool. These include the following. LOP Gas Oil Ratio (GOR) Testing Requirement The LOP requires a GOR test on each producer within 90 to 120 days of commencement of regular production and then semiannually thereafter. The monthly well testing requirements for allocation purposes will provide adequate information as to the producing GOR of the wells so as to render the current rule unnecessary. LOP Gas Cap Water Injection (GCWI) Project: BPXA proposes to remove the 20,000 BWPD injection rate limit and raise the injection pressure limit from 0.55 psi/ft to 0.85 psi/ft. When the LOP GCWI was initially approved it was thought that the water injection rate and pressure must be constrained to prevent parting the LOP matrix to prevent premature water breakthrough. After several years of operation, such strict limits on injection rates and pressure do not appear to be necessary and the GCWI project will still function as planned if injection rates are constrained to 0.85 psi/ft. PMOP Enhanced Oil Recovery (EOR) Project Report: BPXA requests elimination of the annual EOR project report for the PMOP because miscible injectant for this pool is now being supplied by PBU Central Gas Facility and not from the Lisburne Production Center. As such, a PMOP EOR project specific report is no longer needed as the MI composition is the same as elsewhere in the PBU. Conclusions: Each of the affected COs contain an administrative action rule that allows the AOGCC to administratively amend the orders provided the proposed change does not promote waste, jeopardize correlative rights, is based on sound engineering and geoscience principles, and will COs 20713.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 4 of 12 not increase the risk of fluid movement into freshwater. All of BPXA's requested changes comply with these requirements. The proposals to consolidate the rules across the GPMA pools, eliminate or modify the GOR testing and GCWI project rules in the LOP, and eliminating the requirement for an unnecessary EOR project report for the PMOP will simplify operations for BPXA, make uniform the compliance requirements, and will not impact ultimate recovery. Eliminating interwell spacing requirements, while maintaining a minimum offset distance from property lines where ownership changes, will maximize ultimate recovery while also protecting correlative rights. The only proposed change that could potentially have an impact on fluid movement into fresh water is the elimination of the water injection rate limitation and increasing the water injection pressure limitation for the LOP GCWI. However, since the proposed injection pressure limit is below the fracture gradient of the confining interval this will ensure the LOP GCWI injection remains in the LOP. The proposed changes can be made administratively. Finally, on its own motion, the AOGCC is revising the administrative action rules, where necessary, to be consistent and uniform with the language currently used by the AOGCC for these rules. Now, therefore, it is ordered that the subject conservation orders are amended as shown below. Lisburne Oil Pool — Conservation Order No. 207D Rule 3. WELL SPACING There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 9. GAS -OIL RATIO TESTS (Rescinded) Rule 10. PRESSURE SURVEYS a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15' of each year on Form 10- 412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,900 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page 5 of 12 Rule 16. GAS -CAP WATER INJECTION PROJECT a. Water injection is authorized into Well L5-29 only and is limited to perforations within the upper Wahoo Formation (Zone 6) between the measured depths of 13,585' and 13,634'; and b. Injection pressures must be maintained below 0.85 psi/ft. West Beach Oil Pool— Conservation Order No. 311B Rule 3 Well Spacing There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 7 Common Facilities and Surface Comminelina a. Production from the West Beach Pool may be commingled on the surface with production from other pools prior to custody transfer. b. NGLs will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. C. Each producing well will be tested at least once each month. Wells that have been shut-in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. d. Optimum test duration and stabilization time will be determined on a well -by -well basis by the operator. Rule 9 Reservoir Pressure Monitorine a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15`h of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15th of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be COs 20713.001, 31113.003, 31713.003, 3296.005, 345.002,362A.006, 570.010 April 3, 2020 Page 6 of 12 permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. Pt. McIntyre and Stump Island Oil Pools — Conservation Order No. 317B Rule 4 Well Saacina There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 10 Surface Commineline and Common Facilities a. Production from the Pt. McIntyre and Stump Island Oil Pools may be commingled at the surface with production from other pools for processing at the Lisburne Production Center ("LPC") and production from the Pt. McIntyre Oil Pool Drillsite PM2 may be commingled at the surface with production from other pools for processing at the Prudhoe Bay Unit IPA Gathering Center 1 ("GC I"), prior to custody transfer. b. Daily production from all wells will be based on empirical well performance curves derived from 3-phase flow equations and production well test data, and will be a function of flowing tubing pressure and gas -lift rate. The method is described within the "Prudhoe Bay Unit (PBU) Western Satellite Production Metering Plan — Policies and Procedures Document" dated August 1, 2002. c. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operation conditions must be utilized for well testing. d. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. e. Wells will use the associated process facility allocation factor for oil, gas, and water. Pt. McIntyre wells that flow to both GCI and LPC in the same month will use a prorated (GC 1 and LPC) well allocation factor for oil, gas, and water. f Natural gas liquids ("NGLs") processed at the LPC will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. COs 207D.001, 31113.003, 317B.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page 7 of 12 g. NGLs attributable to the PM2 to GCI gas stream and recovered at the CGF will be allocated by calculating the amount of separator off -gas, excluding gas lift gas, attributable to Pt. McIntyre wells producing into GC -1. The percentage of total separator off -gas delivered to the CGF, that is Pt. McIntyre formation gas, multiplied by the total NGL recovery at CGF, yields the amount of NGLs to be allocated to Pt. McIntyre. h. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. Rule 12 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 15a' of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 151 of each year on Form 10- 412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 14 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. Rule 16 Pt. McIntyre Oil Pool Enhanced Oil Recovery Project Injection of miscible injectant for enhanced recovery operations is approved for the Pt. McIntyre Pool. COs 207D.001, 31113.003, 317B.003, 329B.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 8 of 12 Niakuk Oil Pool — Conservation Order No. 329B Rule 3 Well Spacing There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 6 Surface Commineline and Common Facilities a. Production from the Niakuk oil pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. Conduct well tests to determine production rates for each well. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. Sum the TMP volume for all wells in all pools. iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP) v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. d. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. Rule 8 Reservoir Pressure Monitorine a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15'x' of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. COs 207D.001, 311B.003, 31713.003, 32913.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 9 of 12 b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15`h of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 12 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. North Prudhoe Bay Oil Pool — Conservation Order No. 345 Rule 5 Surface Commineline and Common Facilities a. Production from the North Prudhoe Bay Oil Pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. 1. Conduct well tests to determine production rates for each well. 2. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. 3. Sum the TMP volume for all wells in all pools. 4. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP). 5. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGLs will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. COs 207D.001, 311B.003, 317B.003, 329B.005, 345.002, 362A.006,570.010 April 3, 2020 Page 10 of 12 d. At a minimum, each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. e. Optimum test duration and stabilization time will be determined on a well -by - well basis by the operator or, in its discretion, by the AOGCC. Rule 7 Reservoir Pressure Monitoring a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15th of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Rule 11 Administrative Action Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater aquifers. COs 207D.001, 31113.003, 317B.003, 32913.005, 345.002, 362A.006, 570.010 April 3, 2020 Page 11 of 12 Greater Pt. McIntyre Area — Conservation Order No. 362A.005 Rule 1: Lisburne Production Facilities Produced fluids from the Lisburne Oil Pool, West Beach Oil Pool, North Prudhoe Bay Oil Pool, Niakuk Oil Pool, Pt. McIntyre Oil Pool, Stump Island Oil Pool, and Raven Oil Pool may continue to be commingled on the surface for processing at the Lisburne Production Center. Production from each pool may be assigned on the basis of at least once monthly well tests using procedures described in individual conservation orders for those pools or in this order. The AOGCC may approve a different test frequency for individual wells upon application. Raven Oil Pool — Conservation Order No. 570 Rule 3: Well Soacina There shall be no restrictions to well spacing within the affected area except that no pay may be opened in a well which is closer than 500 feet of an external property line where the owners and landowners are not the same on both sides of the line. Rule 6: Common Production Facilities and Surface Commineline a. Production from the Raven Oil Pool may be commingled on the surface with production from other pools for processing at the LPC prior to custody transfer. b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the AOGCC via the Annual Reservoir Surveillance Report. Conduct well tests to determine production rates for each well. ii. Calculate each well's theoretical monthly production (TMP) based on well test rate(s) and actual time on production. iii. Sum the TMP volume for all wells in all pools. iv. Determine an allocation factor as the ratio of the metered volume to the TMP for all wells in all pools (i.e., metered/TMP). v. Calculate each well's actual monthly production (AMP) volume as: AMP = TMP x Allocation Factor c. NGL's will be allocated to each pool based on actual gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to the AOGCC. d. Each producing well will be tested at least once each month. Wells that have been shut in and cannot meet the once -monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determined on a well by well basis by the operator. COs 207D.001, 311B.003, 3178.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 12 of 12 Rule 7: Reservoir Pressure Monitorine a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15' of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year and, unless AOGCC orders otherwise, the plan will be deemed approved 45 days after submission to AOGCC. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual North Raven Oil Pool Reservoir Surveillance Report by June 15' of each year on Form 10-412. Data submitted shall include rate, pressure, time depths, temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9,850 true vertical feet subsea. Transient pressure surveys obtained by a shut-in build-up test, and injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. DONE at Anchorage, Alaska and dated April 3, 2020. Jeremy M. Price Jeremy M. Price Chair, Commissioner Daniel T. wyuy.a.amo.r*. Seamount, Jr. Daniel T. Seamount, Jr. Commissioner RECONSIDERATION AND APPEAL NOTICE Digitally Jessie L. Jeuie - Chmielowski °afe10 - 13:56:53-08'00' Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STNI'E °fALASKA GOVERNOR MIKL DUNLLAVY Mr. Oliver Stemicki Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVALS CONSERVATION ORDER NO. 83A.001 CONSERVATION ORDER NO. 207D.002 CONSERVATION ORDER NO. 311B.004 CONSERVATION ORDER NO. 317B.004 CONSERVATION ORDER NO. 329A.002 CONSERVATION ORDER NO. 3411.002 CONSERVATION ORDER NO. 345.003 CONSERVATION ORDER NO. 452.005 CONSERVATION ORDER NO. 457B.007 CONSERVATION ORDER NO. 471.010 CONSERVATION ORDER NO. 484A.005 CONSERVATION ORDER NO. 505B.003 CONSERVATION ORDER NO. 559A.002 CONSERVATION ORDER NO. 570.011 Well Integrity Engineer Hilcorp North Slope LLC P. O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Numbers: CO -20-004 and CO -20-008 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.oloska.gov Request to amend normal operating limit for inner annulus pressure for non Lisburne development area wells from 2,000 psig to 2,100 psig and to add an administrative approval clause to Conservation Order No. 492 Prudhoe Bay Unit All Oil Pools Dear Mr. Stemicki: By application dated February 24, 2020, Hilcotp North Slope, LLCI (HNS) applied to modify Conservation Order No. 492 (CO 492) to raise the inner annulus (IA) normal operating limit (NOL) reporting threshold from 2,000 psig to 2,100 psig for all wells not processed through the Lisburne Processing Center (LPC)2. CO 492 was issued on June 26, 2003 and applied to all pools in the ' The February 24, 2020, application was submitted by BP Exploration (Alaska) Inc. (BPXA) as operator of the Prudhoe Bay Unit (PBU) but effective on July 1, 2020, BPXA came under new ownership and was renamed HNS. HNS is currently the operator of the PBU. 2 The IA NOL for wells processed through the LPC is currently set at 2,500 psig. HNS is not seeking to modify this at this time. COs 83A.001, 207D.002, 311B.004, 317B.003, 329A.002, 3411.002, 345.003, 452.005, 45713.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 2 of 4 Prudhoe Bay Unit (PBU). The order established rules for dealing with sustained casing pressure for all producers in the PBU. Some, but not all, of the pools in the PBU area have incorporated the rules found in CO 492 directly into its pool rules. CO 492 itself did not contain provisions to allow it the be administratively amended, so providing public notice and opportunity to comment was required in order to amend the order. As such CO 492 will be amended separately and this letter will amend the individual pool rules for the PBU area oil pools. Due to operational changes over time in the PBU, namely increases in the gas lift header pressures, the 2,000 psig NOL for the IA that requires notification to the Alaska Oil and Gas Conservation Commission (AOGCC) when it is exceeded is triggering numerous notifications. These notifications do not on their own require any corrective action to be taken, but simply are a reporting burden on the operator and the AOGCC. Increasing the NOL from 2,000 to 2,100 would decrease the frequency of these notifications. Currently, the NOL for the IA for wells processed through the LPC is 2,500 psig. Exceeding the 2,500 prig NOL triggers a reporting requirement, but does not, standing alone, require corrective action. Another limit that is currently in place, and is not being changed by this action, is a pressure limitation of 45% of the casing's burst pressure rating. Exceeding the 45% pressure limitation requires that corrective action to be taken. Increasing the reporting threshold from 2,000 psig to 2,100 psig for the wells that are not processed at the LPC will eliminate many unnecessary notifications for wells where notification was triggered by the gas lift system pressure instead of an actual problem with the well that might indicate loss of containment. Increasing the IA NOL from 2,000 psig to 2,100 psig for production wells that are not processed at the LPC is based on sound engineering and geoscience principles. Now therefore it is ordered that the text below shall replace the text in the specified rules in the following orders: Conservation Order Oil Pool 207D Lisburne 457B Aurora 484A Polaris 505B Schrader Bluff 559A Put River 570 Raven Rules being replaced 15 11 and 123 10 12 I In the current CO 457B, the pool rules for the Aurora Oil Pool, Rule 11 contains paragraphs a. through f. of the annular pressure rules and Rule 12 contains the definitions in paragraph g. of the annular pressure rules. Paragraph g. is a part of the revised Annular Pressure of Production Wells shown here and thus Rule 12 in CO 457B is being eliminated. COs 83A.001, 207D.002, 31 1B.004,317B.003, 329A.002, 3411.002,345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 3 of 4 And be added as the new rule indicated in the following orders: Conservation Order Oil Pool Added rule 83A Kuparuk River 9 31113 West Beach 14 317B Pt McIntyre and Stump Island 17 329A Niakuk 13 341I Prudhoe Oil Pool 22 345 North Prudhoe Bay 12 452 Midnight Sun 15 471 Borealis 1 I Annular Pressure of Production Wells a. At the time of installation or replacement, the operator shall conduct and document a pressure test of tubulars and completion equipment in each production well that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b. The operator shall monitor each production well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for Commission inspection. c. The operator shall notify the Commission within three working days after the operator identifies a well as having (1) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2100 psig for all other production wells, or (2) sustained outer annulus pressure that exceeds 1000 psig. d. The Commission may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any production well having sustained pressure that exceeds a limit set out in paragraph (c) of this rule. The operator shall give the Commission notice consistent with the requirements of Industry Guidance Bulleting 10-01 A of the testing schedule to allow the Commission to witness the tests. e. If the operator identifies sustained pressure in the inner annulus of a production well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the Commission within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before Commission approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10- 403) a proposal for corrective action. The operator shall give the Commission sufficient notice of the testing schedule to allow the Commission to witness the tests. COs 83A.001, 207D.002, 311 B.004, 31713.003, 329A.002, 3411.002, 345.003, 452.005, 457B.006, 471.009, 484A.005, 505B.003, 559A.002, & 570.011 October 1, 2020 Page 4 of 4 Except as otherwise approved by the Commission under (d) or (e) of this rule, before a shut-in well is placed in service, any annulus pressure must be relieved to a sufficient degree (1) that the inner annulus pressure at operating temperature will be below 2000 psig, and (2) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to (c) but not (e) of this rule may reach an annulus pressure at operating temperature that is described in the operator's notification to the Commission under (c) of this rule, unless the Commission prescribes a different limit. g. For purposes of this rule, I. "inner annulus" means the space in a well between tubing and production casing; 2. "outer annulus" means the space in a well between production casing and surface casing; 3. "sustained pressure" means pressure that (A) is measurable at the casing head of an annulus, (B) is not caused solely by temperature fluctuations, and (C) is not pressure that has been applied intentionally. DONE at Anchorage, Alaska and dated October 1, 2020. Jeremy °'e'm,M;°fCe'r Date: mrato.m M. Price ,3szssue'ov Jeremy M. Price Chair, Commissioner Daniel T.oig,taly signed by oanid T. Seamount h. Seamount, Jr. Date: 2,201001 ,MO_Deno' Daniel T. Seamount, Jr. Commissioner Jessie L. Digitally signed by Jessie L Chmielowski Chmielowski Dme: 2020.10,01 12:22:0 os•oo' Jessie L. Chmielowski Commissioner As provided in AS 31.05.080(x), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl Gordon Severson Richard Wagner K&K Recycling Inc. 3201 Westmar Cir. P.O. Box 60868 P.O. Box 58055 Anchorage, AK 99508-4336 Fairbanks, AK 99706 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith P.O. Box 13557 P.O. Box 39309 Denver, CO 80201-3557 Ninilchik, AK 99639 12 Aombie, Jody J (CED) From: Rixse, Melvin G (CED) Sent: Wednesday, June 10, 2020 2:27 PM To: Sternicki, Oliver R Cc: Colombie, Jody J (CED) Subject: FW: June 25 hearing to amend 4 CO's Attachments: CO -20-008 Public Hearing Notice.pdf,, RE: CO -20-008 This is a clarification email to BPXA, Oliver Sternicki, that the AOGCC interpretation of any development well going through Lisburne Production Center, whether on gas lift or natural flow, will be allowed 2500 psig sustained inner annulus pressure before reporting is required. CO -20-008 as written should be fine. We will then administratively amend the COs per the notice. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or (Melvin Rixselaalaska eovl. cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, June 10, 2020 8:59 AM To: Chmielowski, Jessie L C (CED) <iessie.chmielowski0alaska aov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska aov> Subject: RE: June 25 hearing to amend 4 CO's No one has requested a hearing. Mel: Do you vote to vacate? Jody From: Chmielowski, Jessie L C (CED) <iessie.chmielowski(@alaska gov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, JodyJ (CED) <iody.colombie@alaska.eov> Cc: Rixse, Melvin G (CED) <melvin.rixse(@alaska.eov> Subject: June 25 hearing to amend 4 CO's Hi Jody, Were there any requests to hold the hearing that's scheduled for June 25? Wondering if we can vacate and administratively amend the CO's? Co:`ombie, Jody J (CED) From: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Sent: Tuesday, June 2, 2020 3:43 PM To: Rixse, Melvin G (CED) Cc: Lau, Jack Subject: RE: CO -20-008 Mel, I was doing some work on the NOL increase and noticed something that might need slightly more clarification. The operator shall notify the AOGCC widen three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig- The issue is that this wording could be interpreted as just applying to the gas lifted produces at LPC and excludes the natural flow producers at that facility and in the GPMA area. There are currently 69 wells this applies to. This part should read: ...for wells with supplied gas lift pressure from the Lisburne Processing Center or wells processed through the Lisburne Processing Center... Let me know what you think, Oliver Sternicki o Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver.sternicki(abp.com From: Rixse, Melvin G (CED) <melvin.rixse@alaska.gov> Sent: Friday, May 15, 2020 4:31 PM To: Sternicki, Oliver R <Oliver.Sternicki@bp.com> Subject: FW: CO -20-008 From: Colombie, Jody J (CED) <iodv.colombieC�alasl<a.eov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public Notices(@ liststate ak us> Subject: [AOGCC_Public_Notices) CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools Jody J Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 West T" Avenue Anchorage, AK 99501 (907) 793-1231 Direct (907) 276-7542 Fay List Name: AOGCC Public NoticesCa)list.state ak us You subscribed as: ryan.danielna bp.com Unsubscribe at: httP://Iist.state.ak.us/mailman/or)tions/aogcc public notices/rvan.daniel%40bp.com STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMITINVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVITOFPUBLICATIONWITH ATFACHED COPY OF ADVERTISMENT. ADVERTISINGORDER NUMBER p ,r AO -08-20-024 FROM: AGENCY CONTACT: Jody Colombie/Samantha Carlisle Alaska Oil and Gas Conservation Commission DATE OF A.O.AGENCY PHONE: 333 West 7th Avenue 5/152020 907 279-1433 Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: 907 276-7542 TO PUBLISHER: Anchorage Daily News, LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage, Alaska 99514-0174 TYPE OF ADVERTISEMENT: Fv LEGAL )— DISPLAY .7- CLASSIFIED OTHER (Specify below) o DESCRIPTION PRICE CO -20-008 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWINGADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITHATTACRED COPV OF ADVERTIsh1ENTT0: AOGCC 333 West 7th Avenue Anchors e, Alaska 99501 Page I of I Total of All Pages $ REF Type I Number Amount Date Comments I PVN I VCO21795 2 AD AO -08-20-024 3 4 FPI AMOUNT SY Act. Template PGM LGR Object FY DIST LIQ 1 20 AOGCC 3046 20 2 3 4 5 Porchn u A Title: Purchasing Authority's Signature Telephone Number .. R. 0 receiving agency name must appear on all invoices and documents relatingto this purchase. 2 estate is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and otfor resale. DISTRIBUTION: Division Fiscal/Original AO Copies: Publisher (faxed), Division Fiscal, Receiving Form: 02-901 Revised: 5/21/2020 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: CO -20-008 Prudhoe Bay Field, All Pools BP Exploration Alaska, Inc., by application received February 24, 2020, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 3 of Conservation Orders 317, 505, 559 and 570 to include the following language: The operator shall notify the AOGCC within three working days after the operator identifies a development well as having (a) sustained inner annulus pressure that exceeds 2500 prig for wells with supplied gas lift pressure from the Lisburne Processing Center and 2100 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. In addition, on its own motion AOGCC proposes to add the language that "unless notice and public hearing are otherwise required, upon proper application the AOGCC may administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater." The AOGCC has tentatively scheduled a public hearing on this application for June 25, 2020, at 10:00 a.m. at 333 West 7h Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on June 5, 2020. Due to health mandates issued as a result of the covid-19 virus, if a hearing is requested, the hearing will be held telephonically. Those desiring to participate or be present at the hearing should call 1-800-315-6338 and, when instructed to do so, enter the code 14331. Because the hearing will start at 10:00 a.m., the phone lines will be available starting at 9:45 a.m. Depending on call volume, those calling in may need to make repeated attempts before getting through. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 793-1221 after June 7, 2020. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7's Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on June 22, 2020, except that, if a hearing is held, comments must be received no later than the conclusion of the June 25, 2020 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact theJcmy AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. M. Prj�1i�cNe" Chair, Commissioner Bernie Karl K&K,Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 �J BP Exploration (Alaska) Inc. �6F Attn: Well Integrity Coordinator, PRB-20 ,;.. Post Office Box 196612 Anchorage, Alaska 99519-6612 February 24, 2020 Mr. Jeremy Price Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Request to amend Conservation Order No. 492 rule 3(a) and 6(a). Dear Mr. Price, BP Exploration (Alaska) Inc. requests an amendment to Conservation Order No. 492 rule 3(a) and 6(a) such that current notification and pressure limits are changed from 2000psi to 2100 psi for wells not processed through the Lisburne Processing Center. Current maximum gas lift header pressure in the Prudhoe Bay field for wells not processed through the Lisburne Processing Center regularly exceeds 2000psi. The field - wide IA (Inner Annulus) NOL (Normal Operating Limit) is set at 2000 psi for non -Lisburne development wells, excluding jet pump wells. Beginning in 2015 BPXA began installation of wireless digital annulus pressure gauges on all wells, this was completed in late 2019. Due to the increased accuracy of the annulus pressure readings and realtime monitoring/alerting capability, board operators are now very frequently responding to false alerts of IA NOL excursions on gas lifted wells due to gas lift header pressure exceeding 2000 psi, not sustained casing pressure as intended. BPXA requests that rule 3(a) and 6(a) be changed from 2000psi to 2100 psi (excluding jet pumps) for wells not processed through the Lisburne Processing Center to help minimize bo�rd and well pad operators responding to false alerts. If you have any questions, please call me at 564-5430. Sincerely, Ryan Daniel BPXA Well Integrity Team Lead Attachments: Technical Justification Technical Justification for Conservation Order No. 492 Amendment February 24, 2020 History and Status: Gas lift header pressure at many of the drill sites and pads in the Prudhoe Bay field (excluding wells processed through the Lisburne Process Center) regularly exceeds the 2000 psi IA NOL set for development wells. Gas lift compressor outlet pressures are commonly set at 2100 psi. Historical gas lift pressures can be seen in Figure 1 & 2 for reference. The legacy IA NOL value of 2000 psi was set to remain compliant with Conservation Order No. 492 rule 3(a) and 6(a). Prior to the installation and monitoring of wireless annulus pressure gauges this was not as large of a problem due to one IA pressure read being recorded via mechanical gauge daily per well. If a pressure read exceeded the 2000 psi NOL it was reported to Well Integrity and evaluated to determine if the excursion was SCP or not. Currently all wells in the Prudhoe Bay field have the inner annulus pressures monitored in real-time by either the EOA or WOA production center board operators. The board operators are notified with an alert when the IA pressure of a well exceeds the set NOL value of 2000 psi. This ensures a timely notification and response to any potential excursion event. With the utilization of the wireless annulus pressure gauge alerting it has become an ongoing problem where wells supplied with gas lift pressure are regularly setting off alerts due to the gas lift supply pressure exceeding the 2000 psi NOL and not due to SCP as intended. This excessive alerting has the potential to desensitize workers to possible hazardous occurrences. Increasing IA NOL from 2000 psi to 2100 psi for development wells would eliminate the majority of these false NOL excursion alerts and allow resources to be more focused on response and evaluation of probable SCP events. This increase of 100 psi to the IA NOL is well within the design parameters of development wells across the Prudhoe Bay field. All development wells are included in this request in an effort to reduce the complexity of the IA NOL change. While non gas lifted wells are not subject to the same false alerts there is an increased risk of operating the field with IA NOLs varying for different types of wells. The use of gas lift on development wells, including natural flow producers, is continually changing, some require gas lift for kick off purposes only while others need constant gas lift. Gas lift usage may also change as a well ages depending on depletion or may change due to well work such as add pert/ reperf interventions. The tracking of these dynamic changes would be very difficult and the continual changing of NOL between 2000 psi and 2100 psi for individual wells in multiple data and control systems would greatly increase the complexity and management of NOLs across the field. This inconsistency in IA NOLs would be difficult for field personnel to continually keep track of and would reduce their effectiveness in identification of potential SCP events and would potentially result in misreporting of excursions. The IA NOL increase would not reduce the ability to identify SCP excursions in non -gas lifted wells. BPXA currently monitors development wells for minimum tubing by IA differential pressure thresholds as an indicator of communication. In addition to this SITP of non - gas lifted wells is in excess of 2100 psi, which if seen on the IA would indicate a loss of tubing integrity and would flag as SCP. Based on this it is requested to increase the IA NOL for all development wells (excluding jet pump wells and those processed through the Lisburn Processing Center) to 2100 psi. Figure 1- EOA DS Gas Lift Header Pressure e e y000m EOA Gas Lift Pressure • 3/]Z/m15 5/I/]m5 6/xWm15 8/9/3mS 9/Eft ml6 11/1]/]0x5 VW:m6 LWe Figure 2- WOA Pad Gas Lift Header Pressure !i WOA Gas Lift Pressure I U.. 3/t]/m15 exams WWW 11 6/9ams YnVm15 O/n/xms v5/111x5 xaYmis Oe1e Pec —xPm ry PM PPm —SPM u Pae v Pae r- PM xPm vPm 3Pae •3 B? Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 February 20, 2020 Via USPS and Electronic Delivery Jeremy Price Commission Chair Alaska Oil and Gas Conservation Commission 333 West 701 Avenue, Suite 100 Anchorage, AK 99501 C: Re: Application for Administrative Approval Conforming PBU GPMA Pool Rules for Consistency Amendments to Conservation Orders: 207C, Rules 3, 9c, IOa-f,16c; CO 317B Rules 4, l Ob,d, l Og, 1 Oh, I Oi, 1 Oj, 12a -f, 16b; CO 329A Rules 3, 6b,d, f -j, 8a -f, e; CO 311 B Rules 3, 7b, d, f -k; 9a -f; CO 345 Rules 5b,d,f-i, 7a -f; CO 362A.005 Rule I; CO 570 (Corrected) Rule 3; AA No. 570.002; CO 570.004 Rule 6 b, d, f -i; , l Of governing the development and operation of the Lisburne, Pt. McIntyre, Niakuk, West Beach, North Prudhoe, and Raven Oil Pools Dear Chair Price, BP Exploration (Alaska) Inc. (BPXA), as the operator of the Prudhoe Bay Unit (PBU), respectfully requests that the commission administratively approve amendments described in this application to the referenced Conservation Orders. Each of these pools is in the Greater Pt. McIntyre Area (GPMA) in the PBU. This administrative relief is sought under Rule 17 of CO 207C and its equivalents in the other referenced Conservation Orders. The amendments are proposed with the goal of bringing more efficiency to the management of these reservoirs through achieving as much rule consistency as possible, while still honoring the unique aspects of each pool. More consistent rules will also result in easier monitoring of compliance for the Commission. The proposed changes are in line with recent Commission - approved changes to CO 341F (January, 2018) for the Prudhoe Oil Pool and for changes made to COs 452, 457B, 471, 484A, 505B for the Aurora, Borealis, Orion, Polaris and Midnight Sun Oil Pools (May 29, 2019). With the GPMA Plan Year running April I — March 31, BPXA RECEIVED FEB 2 1 2020 AOGCC respectfully requests adjudication by April 1, 2020 in order that the entire next plan year may be under the new regulations. In overview*, BPXA seeks simplification and consistency for the following: • Well Spacing. BPXA proposes there should be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area, unless the owner and landowner are the same on both sides of the line. This is consistent with the language for the Prudhoe Oil Pool except for the "same landowner" clause which represents an improvement to the POP rule. • Pressure Data 10-412 Report. BPXA proposes to eliminate the monthly (Lisburne) to quarterly (Pt. McIntrye, Niakuk, West Beach) to unspecified (N Prudhoe and Raven) reporting requirement by allowing the operator to annually nominate in the ASR (or if no ASR is required to annually report) the number and approximate locations of pressure surveys, with the AOGCC having 30 days to register an issue; if none is raised the proposed number will take effect. The pressure data report would be included in the ASR with that report replacing Lisburne's requirement for an annual meeting to review pressure monitoring requirements and to discuss plans for reservoir management. All data necessary for analysis of each survey need not be submitted with the report but must be available to the commission upon request. This is the current regulation for the POP. • It is proposed to remove the requirement to determine water volumes, annual API gravity, and annual gas samples from each non -gas lifted producing well in the Surface Commingling and Common Facilities rules as our reservoir recovery mechanisms are not changing. The need for data of this kind on such a frequency is not justified. If the operator were to change the recovery mechanism then it might be prudent to monitor each well in such a manner but barring that, BPXA does not see this data guiding reservoir management decisions. o Allocation Process Reviews. BPXA proposes to formally eliminate this requirement. Instead, this requirement can be replaced with an Allocation Factor report in the Annual Surveillance Report (ASR). P Well Test data Report. BPXA proposes to formally eliminate this requirement for all GPMA pools that currently have it and replace it with the Allocation Factor report in the ASR, as provided for other BP operated pools in AOGCC Administrative Approval (AA) (Docket # CO -15-013) dated 1/7/16. That AA waived the requirement to submit monthly reports of daily allocation and test data for a number of PBU pools. It covered some but not all of the GPMA Pools. P Well Test Frequency. BPXA proposes to go from two to one per month for the GPMA pools. This will be in alignment with the other PBU pools. *Items that pertain solely to individual pools are: proposed elimination of the Lisburne Oil Pool Gas -Oil Ratio Test requirement, proposed upward revision of Injection Gradient and elimination of injection rate limit for the Lisburne Gas Cap Water Injection Project, and proposed elimination of the Pt. McIntyre Oil Pool EOR Project performance report. Rationale behind these "one-off' items is provided in Table 1, a spreadsheet containing all the proposed changes across the six GPMA pools. 2 The specific requests are detailed on an individual pool basis below using the convention of brackets [ ] for deletions of existing order words; use of underline denotes proposed new text. Only those rules and paragraphs within rules that have proposed changes are included below. Lisburne Oil Pool Conservation Order 207C 01 3 M3 6VAII W1 I There shall be no restrictions as to well spacing except that no [The well spacing unit shall be one producing well per governmental quarter section. No] pay shall be opened [in a well closer than 1,000 feet to the pay opened in another well or opened] in a well which is closer than 500 feet to the boundary of the affected area. -'MM-Keymmill aum1 a) Between 90 and 120 days after regular production commences and each six months thereafter a gas -oil ratio test will be taken on each well for as long as it produces oil; b) The gas -oil ratio tests will be for a minimum of four hours and shall be taken at the normal producing rate of the well; and c) The results of the gas -oil ratio tests will be reported on Form 10-409, Gas -Oil Ratio Test and will be submitted in January and July of each year.] a) [All new wells shall have an acceptable pressure survey, as defined in part (c), taken prior to regular production or injection. b) One pressure survey per producing drillsite per year shall be taken. Pressure surveys from producing or water and gas injection wells may be used for this pressure requirement. Pressure surveys covered in section (a) may be substituted for a drillsite pressure. c) Acceptable pressure surveys include static surveys, RFT/FMT, pressure buildup and falloff tests, and multi -rate pressure transient tests in production or injection wells. Other quantitative methods may be administratively approved by the Commission. d) The pressure datum for the Lisburne Oil Pool is 8900 feet subsea. The Commission may administratively amend this datum or create an additional datum when more information is available on the reservoir. e) Data from the pressure surveys, along with additional pressure data obtained through proper management of the reservoir, shall be filed on form 10-412 by the last day of the month following the month that the pressure survey was obtained. Submitted pressure data shall include other information as necessary such as rate, time, depth, temperature, and well conditions to allow for a complete analysis of the pressure survey. f) The operator shall schedule an annual meeting with the Commission to review the pressure monitoring program and discuss future plans for reservoir management.] 3 rll Year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Lisburne Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate pressure time depths temperature and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,900 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test, an iniection well pressure fall-off test a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule. Rule 16, GAS -CAP WATER INJECTION PROJECT [b The Well L5-29 injection rate is limited to 20,000 barrels of water injected per day;] c.Injection pressures must be maintained below 0.85 psi/ft. Pt. McIntyre Oil Pool Conservation Order 317B Rule 4 Well Spacing There shall be no restrictions as to well spacing except that no [The spacing unit shall be one producing well per 40 acres or quarter -quarter governmental section. No] pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 10 Surface Commingline and Common Facilities b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission [quarterly in both computer file and report formats.] via the Annual Reservoir Surveillance Report. No changes to the remainder of b (sub paragraphs). d. Each producing well will be tested at least [twice] once each month. Wells that have been shut in and cannot meet the [twice] once monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. e. The operator shall submit a review of pool production allocation factors and 4 issues over the prior year with the annual reservoir surveillance report and retain electronic file(s) containing daily allocation data and daily test data for a minimum of five years. Data shall be presented on a monthly basis, reported annually in the ASR. [10f) API gravity will be determined for each producing well annually by an API/MPMS approved method. log) Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. l0h) Quarterly allocation process reviews will be held with the Commission. 10i) This rule may be revised or rewritten after an evaluation period of at least one year.] I kIM ra rMUTTTIMINZW7747" Ia. Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be run annually. The surveys in part a. of this rule may be used to fulfill the minimum requirements c. The datum for all surveys is 8800' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request. f. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part e. of this rule.] year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b.Data from the surveys required in (a) of this rule shall be submitted with the Annual Pt. McIntyre Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10- 412. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test, an injection well pressure fall-off test, a multirate test, or an interference test are acceptable Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c.Results and data from any special reservoir pressure monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule. Rule 16 Pt. McIntyre Oil Pool Enhanced Oil Recovery Proiect [b. An annual report must be submitted to the Commission detailing performance of the PMOP Enhanced Oil Recovery Project and outlining compositional information for the current miscible injectant necessary to maintain miscibility under anticipated reservoir conditions. The report should be submitted in conjunction with the PMOP Annual Reservoir Report.] Niakuk Oil Pool Conservation Order 329 [Upon application ofthe operator, the Commission may administratively approve the drilling of any well to a bottom hole location greater than 500 lineal feet from the external boundary of the affected area. No well bore may be open to the Niakuk oil pool within 500 feet of the external boundary of the affected area nor within 1000 feet of another well capable of producing from the same pool.] There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 6 Surface Commineline and Common Facilities b. Production from each well will be determined by the following well test allocation methodology. Allocation data and well test data will be supplied to the Commission [monthly in both computer file and report formats.] via the Annual Reservoir Surveillance Report. No changes to the remainder of b (sub paragraphs). d.Each producing well will be tested at least [twice] once each month. Wells that have been shut in and cannot meet the [twice] once monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. [£Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. g.API gravity will be determined for each producing well annually by an API/MPMS approved method. h.Gas samples will be taken and analyzed for composition from each non gas lifted C producing well yearly. i.Quarterly allocation process reviews will be held with the Commission. j.This rule may be revised or rewritten after an evaluation period of at least one year.] Rule 8 Reservoir Pressure Monitoring a. [Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. b. A minimum of one bottom hole pressure survey per producing governmental section shall be obtained annually. The surveys in part'a' of this rule may be used to fulfill the minimum requirements. c. The datum for all surveys is 9200' TVDss. d. Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom hole pressure after the well has been shut in for an extended period. e. The pressure surveys will be reported to the Commission quarterly on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted upon request. Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part'e' of this rule.] This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by 15 of that year. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual Niakuk Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test, an injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. 7 C. Results and data from any special reservoir pressure monitoringtechniques, echniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. West Beach Oil Pool Conservation Order 311B Rule 3 Well Soacine There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. [Statewide 160 -acre drilling units are in effect until such time as data or circumstances warrant the Commission to approve a change.] Rule 7 Common Facilities and Surface Comminelin¢ [(b) Production from each pool will be determined by the following well test allocation method. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats.] (d) Each producing well will be tested at least [twice] once each month. Wells that have been shut-in and cannot meet the [twice]once-monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. [(f) Water volumes will be determined by API/MPMS approved methods, or the use of industry proven on-line water cut measurement devices. (g) API gravity will be determined for each producing West Beach well monthly. (h) Gas samples will be taken for each non -gas lifted producing well yearly. (i) Quarterly allocation process reviews will be held with the Commission. 0) Prior to installing separate test facilities (if required by future development) at West Beach, Commission approval of the facilities must be obtained. (k) This rule may be revised or rewritten after an evaluation period of at least one year.] Rule 9 Reservoir Pressure Monitorine [(a) Prior to regular production, a pressure survey shall be taken on each well to determine the reservoir pressure. (b)A minimum of one bottom -hole pressure survey per producing governmental section shall be run annually. The surveys in part (a) of this rule may be used to fulfill the minimum requirements. (c)The datum for all surveys is 8,800' TVD SS. (d)Pressure survey will be a pressure buildup, pressure falloff, RFT, or static bottom -hole pressure after the well has been shut in for an extended period. (e)The pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pressure Report, shall be used to report results from these surveys. All data necessary for complete analysis of each survey need not be submitted with the form 10-412 but must be submitted D on request. (f)Results and data from any special reservoir pressure monitoring techniques, tests, or surveys also shall be submitted in accordance with part (e) of this rule.] a. An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in coniunetion This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that ,year. b. Data from the surveys required in (a) of this rule shall be submitted with the Annual West Beach Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10- 412. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 8,800 true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test, an injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoringtechniques, chniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. North Prudhoe Bay Oil Pool Conservation Order 345 Rule 5 Surface Commingling and Common Facilities (b) Production from each well will be determined by the following well test allocation methodology. Allocation data and well test datawill be supplied to the Commission via the Annual Reservoir Surveillance Report. [monthly in both computer file and report formats.] No changes to the remainder of b (subparagraphs). (d) At a minimum, each producing well will be tested at least once [twice] each month. Wells that have been shut in and cannot meet the once [twice] monthly test frequency must be tested within five days of startup. [(t) Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. (g) API gravity will be determined for each producing well annually by an API/MPMS approved method. (h) Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. (i) The allocation process for the North Prudhoe Bay Oil Pool will be reviewed with the Commission in conjunction with scheduled LPC allocation review.] Rule 7 Reservoir Pressure Monitoring [7a) Prior to regular production, a pressure survey shall be taken on each well to determine the reserv0l r pressure. 0 7b) Until a secondary recovery project is approved and implemented, a minimum of one bottom- hole pressure survey per producing governmental section shall be obtained annually. 7c) The datum for all surveys is 9245'TVDss. 7d) Pressure surveys will be either a pressure buildup, pressure falloff, RFT, or static bottom- hole pressure after the well has been shut in for an extended period. 7e) The pressure surveys will be reported to the Commission on form 10-412, Reservoir Pressure Report. All data necessary for complete analysis of each survey need not be submitted with the form 10-412, but must be submitted upon request. 7f) Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part'e' of this rule.] year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that year. b.Data from the surveys required in (a) of this rule shall be submitted with the Annual North Prudhoe Bay Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9245 true vertical feet subsea. Transient pressure surveys obtained by a shut-in buildup test, an injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c. Results and data from any special reservoir pressure monitoring techniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. Raven Oil Pool Conservation Order 570 Rule 3: Well Spacing [To allow for close proximity of wells in separate fault blocks, spacing within the pool will be a minimum of 20 acres. The ROP shall not be opened in any well closer than 500 feet to the external property lines where ownership or landownership changes.] 10 There shall be no restrictions as to well spacing except that no pay shall be opened in a well closer than 500 feet to the boundary of the affected area. Rule 10: Annual Reservoir Surveillance Report [f. By August 1 of each year, the Operator shall schedule and conduct a technical review meeting with the AOGCC to discuss the report contents and to review items that may require action within the coming year by the AOGCC. The AOGCC may conduct audits of technical data and analyses used in support of the surveillance conclusions and reservoir depletion plans.] Rule 6: Common Production Facilities and Surface Commingling c. All wells must be tested a minimum of [twice] once per month. The AOGCC may require more frequent or longer tests if the allocation quality deteriorates. Wells that have been shut in and cannot meet the [twice] once monthly test frequency must be tested within five days of startup. All available test separator capacity within the constraints imposed by operating conditions must be utilized for well testing. d. [The operator shall submit a monthly report and file(s) containing daily allocation data and daily test data for agency surveillance and evaluation.] Allocation data and well test data will be supplied to the Commission via the Annual Reservoir Surveillance Report. [f.Water volumes will be determined by API/MPMS approved methods, or the use of industry proven, on-line water cut measurement devices approved by the Commission. g.API gravity will be determined for each producing well annually by an API/MPMS approved method. h.Gas samples will be taken and analyzed for composition from each non gas lifted producing well yearly. LQuarterly allocation process reviews will be held with the Commission.] Rule 7: Reservoir Pressure Monitoring a. [Prior to regular production or injection, an initial pressure survey must be taken in each well. b. A minimum of one pressure survey will be taken annually in each of the ROP reservoir compartments where production wells exist. C. The reservoir pressure datum will be 9,850' feet true vertical depth subsea. d. Pressure surveys may consist of stabilized static pressure measurements (bottom - hole or extrapolated from surface), pressure fall-off tests, pressure build-up tests, multirate tests, drill stem tests, and open -hole formation tests. e. Data and results from pressure surveys shall be submitted with the annual reservoir surveillance report. All data necessary for analysis of each survey need not be submitted with the report but must be available to the AOGCC upon request. f. Results and data from special reservoir pressure monitoring tests shall also be submitted in accordance with part (e) of this rule.] 11 a.An Annual Pressure Surveillance Plan shall be submitted to the AOGCC in conjunction with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15th of each year. This plan will contain the number and approximate location of pressure surveys anticipated for the next calendar year, and it will be subject to approval by the AOGCC by July 15 of that b.Data from the surveys required in (a) of this rule shall be submitted with the Annual Raven Oil Pool Reservoir Surveillance Report by June 15 of each year on form 10-412. Data submitted shall include rate, pressure, time depths, temperature, and any well condition necessary for the complete analysis of each survey. The datum for the pressure surveys is 9,850' true vertical feet subsea. Transient pressure surveys obtained by a shut- in buildup test an injection well pressure fall-off test, a multirate test, or an interference test are acceptable. Calculation of bottom -hole pressures from surface data will be permitted for water injection wells. Other quantitative methods may be administratively approved by the AOGCC. c.Results and data from any special reservoir pressure monitoringtechniques, chniques, tests, or surveys shall also be submitted as prescribed in (b) of this rule. If you have any questions regarding this request, please contact Bill Bredar at 564-5348 or through email at William.bredar@bp.com. Sincerely, ,a/ -&7 Katrina Garner PBU Area Manager Cc: J. Schultz, CPAI J. Farr, ExxonMobil Alaska, Production Inc. D. White, Chevron USA D. Sturgis, ExxonMobil Alaska, Production Inc. E. Reinbold, CPAI D. Roby, AOGCC 12 Y —__ Table 1. GPMA Current vs. Proposed Conservation Order Changes (part of Application for Administrative Approval Conforming PBU GPMA Pool Rules for Consisting( 13abom. RewlwmrtCpmx Carn.mn MR[Regmmnmt euwgwci Rprrx.m.m CYnemwwte„eF cum OF. 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That" r F" nfnae ingrt on Yedwr nen m.. a, I the "-_- 1L1 no ParMen onNmelryenpnmeYmn Yreyued.. Prod.bnenana reswmemlMurna[CNIhe10 mNlm tlreymOneogrn rnPonO to ywmF oryNtr mn .gimme rebNe mawgmem. Nd env a Ymn ~8 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Group 1 IPA Group 2 GPMA Group 3 Satellites __~_____...______.__mm I------~----- ._--_.._~--_.._-_.._----- Annual Surveillance Report 15-Mar 15-Jun 15-Sep 1-----_.. - .~----_._. ----.-.--- I------~~---------- -- -._-~._.._-----------_._-_._- ~-~._-..~---------".,.-.~_._._-^ .--.--- !--------_._-~----- -- Annual Overview Presentation 22-Mar 22-Jun 22-Sep _.__..~,~--~_. -- --- I-- --~ Production Period to be Covered Jan 1-Dec 31 Apr 1-Mar 31 Jul 1-Jun 30 . Amends Order/Rule Gro_up 1 -1~~_ºilfo~J~_________ m__ _________ Order Date Comment Prudhoe Oil Pool -~._------_.-"'-'-----'---""'--'-'---'--"'..~---_.-----.--_._~-_._-.---- Put River Oil Pool C0341D Rule 11 .------------- -. ----.+- C0559 11/30/2001 ,.-.... -- "._.__._----~---------- 11/22/2005 Note C0341 E (modified Pool Definition to include a portion of Put River Sandstone) ----- - Corrected 2/14/2006 Group 2 - GPMA Oil Pools -- -.--- _.m___ -__.._..._.~_ -----..-----1----.. . .- .-..-.---.---. -------.- Lisburne C0207 207 A .- ... .--.--------.-------- ------.---------------------.- Niakuk C0329A Rule 9 6/4/1996 ----.--. -.--- .._----------_._-~--_._._~--_.---_._.~----- --.-- North Prudhoe Bay C0345 Rule 8 12/16/1994 ---....---- ---- -_._._---_._-_._----_.~------'-- --_.._---_._-----~ ----- _____ _____________ Pt. Mc.!~ C0317B Rule 15 4/19/2000 Raven Oil Pool C0570 Rule 10 8/9/2006 -- ---.- --.... --------_._._~--_._.._-_.-._---~----- West Beach Oil Pool C0311 BRule 13 8/1/2000 ------- ~--~-- i No rule on Surveillance reports --1----- --------- ~..=~--~~~_--:- -== .___~·____·_.______·_m_··_·____ . Group 3 - Prudhoe Satellite Oil Pools ..... ___ - ___......______ .._________._____ __.___.____.._________.____.____._________________..._______··_···_·__m______·__ ....__. ___ __________~uror~ _. _--º_º~_?!B RuJ~ª_._______?!?5/200~_____r-___(c:~~~~~ted 8/9!'?Q04) __________ .. ....~....-~!.e~ ___ CO~?1 Rule~_______~?!29/2002______J_----------- _______________ _____nmJ'.lli~~ight _ª-i.J!".1 _____C045~~~le 1 !-~f------- 11 /15/2000 ..__~------------- ______________~ - ----------- -p~~~~ --- - -gg~~~~-=~::l--------~!1~~j~~~: m_ --~-- - ------- ------- l"'" .,-. l~ ,,_. ~-_. ----. -..............-- .-["'...-..... --"'-"-'jj . . Subject: [Fwd: [Fwd: Re: surveillance report dates]] From: Jane Williamson <jane_williamson@admin.state.ak.us> Date: Fri, 20 Apr 2007 13:03:59 -0800 To: Jody J Colombie <jody_colombie@admin.state.ak.us>, Dave Roby <daveJoby@admin.state.ak.us>, Cathy P Foerster <cathy_foerster@admin.state.ak.us>, Alan J Birnbaum <alan _ birnbaum@law.state.ak.us> cc: Stephen E Mcmains <steve_mcmains@admin.state.ak.us>, art Saltmarsh <art _ saltmarsh@admin.state.ak.us>, Thomas E Maunder <tom _ maunder@admin.state.ak.us> There is something didn't get around to before Ieft and that was to administratively amend the COs for PBU to include reporting dates agreed to verbally with BP (and DNR). Really, only pt. Mcintyre and Borealis have the wrong dates in the CO's. The others are either ok, or not explicit. Attached are the COs affected. I'm not sure how you want to handle. Jody. Please put this in the following CO files along with the attachment. Group 1 - IP A Oil Pools Prudhoe Oil Pool C0341 D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne C0207, 207 A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C0311B Group 3 - Prudhoe Satellite Oil Pools Aurora C0457B Boreallis C0471 Midnight Sun C0452 Orion C0505A Polaris C0484A -------- Original Message -------- Subject:Re: surveillance report dates Date:Thu, 31 Aug 2006 17:27:45 -0800 From:Jane Williamson <¡ane williamson~admin.state.ak.us> Organization:State of Alaska To:Lenig, David C <David.Lenig(â¿bp.com> References:<CBF4D8E92B5A 704 79F64416582FóA 17CB81AEO(ã?bp 1 a..'lcex005.bp l.ad.bp.com> Oops Lenig, David C wrote: Hi Jane, 10f3 4/23/2007 9:50 AM l" ..-. l4 ,'....... ......,.,............... ''''''.."..-.....-..... ..-t'........... --............JJ . . j djdn:t get the attachrTìent !)avid From: Jane Williamson Sent: Thursday, August 31,20065:14 PM To: Lenig, David C Subject: Re: surveillance report dates E-mail is fine. Attached is a list of the pools and orders/rules that will be amended with the Admin approval. Take a look and see if this looks right to you. (Note, I'm only listing the rules that are affected by the new dates - there may be additional amendments unrelated to the surveillance requirements that I've not listed.) I'm flexible on the date for the Overview presentation. I'd be fine with specifying it to be within one or two months of the report date rather than the POD overview that you've noted. What would you prefer? Lenig, David C wrote: Jane, Here is a table showing the dates for the various Reports and Presentations. I've added the production period as well. The IPA review date remains problematic due to the proximity to spring break but we seem to work around it each year. Would you prefer that I put this in a letter requesting the changes? I know we talked about this a little while ago I just haven't found the time. Thanks, David Plan of Development Production Period Jul1-Jun30 IPA GPMA March 15 June 15 September 15 March 22 June 22 September 22 March 30 June 30 September 30 Jan1-Dec31 Apr1-Mar31 Satellites Annual Surveillance Report Annual Overview Presentation -----Original Message----- From: Jane Williamson [mailto:jane wlllìamson@ad~in.state.ak.us] Sent: Thursday, August 31, 2006 2:30 PM To: Lenig, David C Subject: surveillance report dates Hi David. When you get a second, could you please send back an e-mail that lists all the surveillance report dates that we've agreed to for all PBU pools (including GPMA)? Also, do you have dates for surveillance reviews? I'll go through the list and make sure the Conservation orders are correctly worded, then put out administrative amendments as necessary. I checked with Cammy and she said an e-mail is fine for starting the 20f3 4/23/2007 9:50 AM l" ....... l" ....... ","_.~"'--' .-......-.....-- .-t"'.......,,~ _.....""-~.I.J administrative action ~cess. . Thanks. Jane '¡,JVillian1S0rl~ PE <~ane '.villiamson(ã¿adr(li11.state.al(~us> Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission Content-Type: applicationlvnd.ms-excel surveillance report.xls Content-Encoding: base64 30f3 4/23/2007 9:50 AM *7 Re: West~each Watertlood: Update . . Subject: Re: West Beach Waterflood: Update Date: Tue, 25 Jul2000 18:01:55 -0900 From: "Paul J Taylor" <pjtaylor@ppco.com> To: "Jack Hartz <jack_hartz" <jack_hartz@admin.state.ak.us> cc: "Gordon Kidd" <gkidd2@ppco.com>, Barnes&Robinson/ AAI/ ARCO <Bames&Robinson/ AAI/ ARCO@ppco.com>, FrazieRB@BP.com, "Scott A Mattison" <smattis@ppco.com>, "William L Mathews" <wmathews@ppco.com> cVHi Jack. We did do some preproduction sensitivities that showed little impact on reserves with timeframes that went up to two years. Admittedly, though, the GORs are near marginal, reservoir pressures are low, and it's summer on the slope, so shutting WB-04 in for a while is not a big deal. My hope was to defer making a decision until we get the results from the high pressure breakdown. That should happen fairly soon. A one week extension (past July 31) will probably cover us for this. We could then discuss plans later if the breakdown is delayed or unsuccessful. Does that sound reasonable? Paul 0::~k ft¡ <jack_hartz@admin.state.ak.us> r;~-~ to ~ on 07/25/2000 03:11:33 PM Hartz Paul J Taylor/AAI/ARCO@Arco Camille Oechsli <cammy_oechsli@admin.state.ak.us>, JR <dan seamount@admin.state.ak.us> Subject: Re: West Beach Waterflood: Update cc: Daniel T Seamount Paul, Thanks for the W Beach update. I am reviewing the data from the WB wells and note the GORs range upward to 15000+ SCF/STB and that reservoir pressure is around 3000 psi, down from about 4260 psi initial. Has there been any work done to verify whether long term ongoing primary production has the potential to do reservoir damage? That would be our greatest concern on continuation of production without injection. Of course it depends on how long it will be until WB-06 is ready for injection. You mentioned it could take up to a month or longer. Is that the downside time estimate? Let me know what you think. Jack Hartz Paul J Taylor wrote: > Jack, > > As of today we are still experiencing problems with the conversion of WB-06 > and would like to apply for the extension of AA 311.07. The plan forward is > as follows: 10f3 7/28/004:57 PM Re: West Beach Watertlood: Update . . > > > > > > > > > > If steps 1 & 2 are successful, we could be near the 10 day mark now. If > not, it could be upwards of a month or longer before the well is converted. > We will contact you after step 2 to give you an update of our progress. > > If you have any questions, please reply or call (263-4822). > > Paul Taylor > > Jack Hartz <jack_hartz@admin.state.ak.us> on 07/21/2000 08:08:43 AM > > To: > cc: > Gordon > Kidd/AAI/ARCO@Arco, Paul J Taylor/AAI/ARCO@Arco > Subject: Re: West Beach Waterflood > > Mike, Paul, Gordon, > > Mike, thanks for the heads up on the start of injection and the possibility > it will > be delayed into August. apply > for an > extension of AA 311.07. the > application, give a notification of when you expect to begin injection. > The > operator must notify the Commission at least ten days prior to start of > injection > according to 20 AAC 25.420 . > > The 24 month clock you mention is in 20 AAC 25.402(i), not (f). Paragraph > (i) means > that the injection project must start within 24 months of the date of AIO > 4C, April > 19, 2000. > expire > unless an extension is granted. > > > > > > Thanks, > > Jack Hartz > > Mike R Morgan wrote: > > > Hello Jack, 1) Replace integrity. 2) Attempt 3) Failing string. 4) Repeat clean-out, conversion process. all live lift gas mandrels with dummies, establish packer to break down perfs with high pressure injection. that, attempt to produce the well again using a coil siphon sample fill, stimulate (if necessary), restart Mike R Morgan/AAI/ARCO@Arco blair_wondzell@admin.state.ak.us, bob_crandall@admin.state.ak.us, tom_maunder@admin.state.ak.us, steve_davies@admin.state.ak.us, I recommend that you wait until next week to You can apply for the extension by email. In If the project is not begun by April 18, 2002 the order will I will be in the office all week 7/24-28 and out on 7/31. Have Paul or Gordon contact me if it is unlikely that injection will start by 7/31. 20f3 7/28/004:57 PM Rs.: W~stBeach Watertlood: Update . . > > > > As a follow-up to my phone message, I just wanted to let you know the > status of > > the West Beach Waterflood Project. WB-07, > on June > > 10, 2000 and have been finalizing the tie-in and conversion preparatory > work on > > WB-06. the > end of > > the month it may slip into August. the > July > > 7, 1999 GOR waiver allowing production from the West Beach Pool through > July 31, > > 2000, or does the April 19, 2000 approval of the West Beach Enhanced > Recovery > > Project cover it with the start of the 24 month clock under 20 AAC > 25.402(f)? > > > > Please respond to Paul Taylor (263-4822, e-mail above) or Gordon Kidd > (263-4103, > > e-mail above) as I will be out of town until August 1, 2000. Paul and > Gordon > > both will be working for BPA, the new operator of the West Beach Pool. > > > > Best regards, > > > > > > > > > > > > (See attached file: jack_hartz.vcf) We completed the source well, Although our target is to have water injection started before Will you need a request to extend Mike Morgan Phillips Alaska Exploration and 907-263-4332 Inc. Land (See attached file: jack_hartz.vcf) L" _,w_wn~_mm~,····, Jack Hartz <Jack Hartz@admin.state.ak.us> Sf. Reservoir Engineer Alaska Oil & Gas Conservation Commission 30f3 7/28/004:57 PM WestBeach Watertlood: Update . . éP Jack, Subject: West Beach Waterflood: Update Date: Tue, 25 Jul 2000 10:04:40 -0900 From: "Paul J Taylor" <pjtaylor@ppco.com> To: "Jack Hartz <jack_hartz" <jack_hartz@admin.state.ak.us> cc: "Gordon Kidd" <gkidd2@ppco.com>, FrazieRB@BP.com, "Barnes&Robinson" <p1466@ppco.com> are still expe~n~ems with the to apply for the extension of AA 311.07. conversion of WB-06 The plan forward is As of today we and would like as follows: 1) Replace all live lift gas mandrels with dummies, establish packer integrity. 2) Attempt to break down perfs with high pressure injection. 3) Failing that, attempt to produce the well again using a coil siphon string. 4) Repeat clean-out, sample fill, stimulate (if necessary), restart conversion process. If steps 1 & 2 are successful, we could be near the 10 day mark now. If not, it could be upwards of a month or longer before the well is converted. We will contact you after step 2 to give you an update of our progress. If you have any questions, please reply or call (263-4822). Paul Taylor To: cc: ~ Hart. <jack hartz@admin.state.t!J> !:æ~OO~8:::~::Ö;:C ,.. ø.-J/.J- Mike'R Mor~an/AAI/ARCO@Arco ~Tf~) blair wondzell@admin.state.ak.us, bob crandal1@admin.state.ak.us, tom maunder@admin.state.ak.us, steve davies@admin.state.ak.us, Gordon Kidd/AAI/ARCO@Arco, Paul J Taylor/AAI/ARCO@Arco Subject: Re: West Beach Waterflood œ Mike, Paul, Gordon, Mike, thanks for the heads up on the start of injection and the possibility it will be delayed into August. I recommend that you wait until next week to apply for an extension of AA 311.07. You can apply for the extension by email. In the application, give a notification of when you expect to begin injection. The operator must notify the Commission at least ten days prior to start of injection according to 20 AAC 25.420 . The 24 month clock you mention is in 20 AAC 25.402(i), not (f). Paragraph (i) means that the injection project must start within 24 months of the date of AIO 4C, April 19, 2000. If the project is not begun by April 18, 2002 the order will expire unless an extension is granted. 10f3 7/28/004:57 PM West Beach Watertlood: Update . . I will be in the office all week 7/24-28 and out on 7/31. Have Paul or Gordon contact me if it is unlikely that injection will start by 7/31. Thanks, Jack Hartz Mike R Morgan wrote: > Hello Jack, > > As a follow-up to my phone message, I just wanted to let you know the status of > the West Beach Waterflood Project. on June > 10, 2000 and have been finalizing the tie-in and conversion preparatory work on > WB-06. end of > the month it may slip into August. July > 7, 1999 GOR waiver allowing production from the West Beach Pool through July 31, > 2000, or does the April 19, 2000 approval of the West Beach Enhanced Recovery > Project cover it with the start of the 24 month clock under 20 AAC 25.402(f)? > > Please respond to Paul Taylor (263-4822, e-mail above) or Gordon Kidd (263-4103, > e-mail above) as I will be out of town until August 1, 2000. Paul and Gordon > both will be working for BPA, the new operator of the West Beach Pool. > > Best regards, > > > > > We completed the source well, WB-07, Although our target is to have water injection started before the Will you need a request to extend the Mike Morgan Phillips Alaska Exploration and 907-263-4332 Inc. Land (See attached file: jack_hartz.vcf) L... Jack Hartz <Jack Hartz(a}admin.state.ak.us> Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission 20f3 7/28/004:57 PM ·. .- - JHMemo.txt Please file in CO 311 and CO 3116. --------------------------------------------------------------------- Subject: Re: West Beach Waterflood Date: Fri, 21 Jul 2000 10:08:43 -0700 From: Jack Hartz <jack_hartz@admin.state.ak.us> Organization: Alaska Oil and Gas Conservation Commission To: Mike R Morgan <MIKERM@ppco.com> CC: blair_wondzell@admin.state.ak.us, bob_cra ndall@admin.state.ak.us, tom_mau nder@admin.state.ak.us, steve_davies@admin.state.ak.us, Gordon Kidd <GKIDD2@ppco.com>, Paul J Taylor <PJTAYLOR@ppco.com> Mike, Paul, Gordon, Mike, thanks for the heads up on the start of injection and the possibility it will be delayed into Aug ust. I recommend that you wait until next week to apply for an extension of AA 311.07. You can a pply for the extension by email. In the application, give a notification of when you expect to begin injection. The operator must notify the Commission at least ten days prior to start of injection acco rding to 20 AAC 25.420 . The 24 month clock you mention is in 20 AAC 25.402(i), not (f). Paragraph (i) means that the inje ction project must start within 24 months of the date of AIO 4C, April 19, 2000. If the project is no t begun by April 18, 2002 the order will expire unless an extension is granted. e I will be in the office all week 7/24-28 and out on 7/31. Have Paul or Gordon contact me if it is unli kely that injection will start by 7/31. Thanks, Jack Hartz Mike R Morgan wrote: > Hello Jack, > > As a follow-up to my phone message, I just wanted to let you know the status of > the West Beach Waterflood Project. We completed the source well, WB-07, on June > 10, 2000 and have been finalizing the tie-in and conversion preparatory work on > WB-06. Although our target is to have water injection started before the end of > the month it may slip into August. Will you need a request to extend the July > 7, 1999 GOR waiver allowing production from the West Beach Pool through July 31, > 2000, or does the April 19, 2000 approval of the West Beach Enhanced Recovery > Project cover it with the start of the 24 month clock under 20 AAC 25.402(f)? > > Please respond to Paul Taylor (263-4822, e-mail above) or Gordon Kidd (263-4103, > e-mail above) as I will be out of town until August 1, 2000. Paul and Gordon > both will be working for BPA, the new operator of the West Beach Pool. > > Best regards, > > Mike Morgan . Page 1 .. - > Phillips Alaska Inc. > Exploration and Land > 907-263-4332 JHMemo.txt .. --------------------------------------------------------------------- Jack Hartz <Jack_Hartz@admin.state.ak.us> Sr. Reservoir Engineer Alaska Oil & Gas Conservation Commission e e Page 2 West Beach Watertlood . . Subject: West Beach Waterflood Date: Thu, 20 Jul 2000 15: 15 :26 -0900 From: "Mike R Morgan" <MIKERM@ppco.com> To: jack_hartz@admin.state.ak.us CC: blair_ wondzell@admin.state.ak.us, bob _crandall@admin.state.ak.us, tom _ maunder@admin.state.ak.us, steve _ davies@admin.state.ak.us, "Gordon Kidd" <GKIDD2@ppco.com>, "Paul J Taylor" <PJTA YLOR@ppco.com>, "Leslie B Senden" <LSENDEN@ppco.com>, "Anthony D Jackson" <AJACKSON@ppco.com> o Hello Jack, ff~ cÞ¡J As a follow-up to my phone message, I just wanted to let you know the status of the West Beach Water flood Project. We completed the source well, WB-07, on June 10, 2000 and have been finalizing the tie-in and conversion preparatory work on WB-06. Although our target is to have water injection started before the end of the month it may slip into August. Will you need a request to extend the July 7, 1999 GOR waiver allowing production from the West Beach Pool through July 31, 2000, or does the April 19, 2000 approval of the West Beach Enhanced Recovery Project cover it with the start of the 24 month clock under 20 AAC 25.402(f)? Please respond to Paul Taylor (263-4822, e-mail above) or Gordon Kidd (263-4103, e-mail above) as I will be out of town until August 1, 2000. Paul and Gordon both will be working for BPA, the new operator of the West Beach Pool. Best regards, Mike Morgan Phillips Alaska Inc. Exploration and Land 907-263-4332 1 of 1 7/28/004:58 PM 1¡6 ... ARCO Alaska, Inc. . . Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 .. ~~ ~~ Greater Pt. Mcintyre Area March 9, 2000 Robert N. Christenson, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 RE: Question Raised at the January 12-13 Hearing on Proposed Amendment to Area Injection Order No. 48. Dear Mr. Christenson: This letter is in response to a question that was asked at the January 12-13 hearing on proposed amendment to Area Injection Order 48. With respect to the Pt. Mcintyre miscible Enhanced Oil Recovery (EaR) project, you asked what would be the magnitude of the MMP buffer resulting from the thermal cooling of the rock by injected source water. Pt. Mcintyre injects source water at a temperature of approximately 75 degrees Fahrenheit into a reservoir originally at 182-185 degrees Fahrenheit. Reservoir temperature increases away from the injection well to the limits of the temperature bulb. Calculations show that the MMP drops by at least five psi for every one degree of temperature decrease. Thermal modeling shows that the reservoir temperature is currently reduced by at least 10 degrees Fahrenheit to a distance of at least 550 feet from a typical EaR injection well, providing an MMP buffer of at least 50 psi. The radius of this buffer will increase with time as the temperature bulb propagates further from the injection wells. As was stated in the hearing testimony, Pt. Mcintyre will be operated to maintain reservoir pressure at original pressure, nominally 4370 psi. This operating practice significantly reduces the requirement of an MMP buffer as compared to other fields that are not operated in this manner. In addition, a new analytical technique for estimating MMP developed by Wang and Peck (SPE 59378) has been applied to the Pt. Mcintyre fluid characterization. This technique has indicated that the MMP could be as low as 4050 psi, resulting in a buffer of approximately 300 psi. ORIG1;\L~L ARea Alaska. Inc. is a Subsidiary of AtlanticRichfieldCompany .. .. Please contact J. W. Groth (265-6846) or J. L. Hand (265-6036) if you have questions or require additional information. Sincerely, cc: D. W. Bose (AAI) M. P. Evans (ExxonMobil) J. Hurliman (SPA) ~ 10 11 12 13 14 15 16 17 18 19 20 21 II 2211 23 II " II 24 Ii II 2511 ,I I, II II ¡¡ Ii i . . 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 PUBLIC HEARING 3 In Re: 4 POINT McINTYRE OIL POOL ENHANCED OIL 5 RECOVERY PROJECT and WEST BEACH OIL POOL SECONDARY RECOVERY PROJECT APPLICATION 6 FOR INJECTION AND AMENDMENT TO AREA INJECTION ORDER NO. 4B. 7 8 TRANSCRIPT OF PROCEEDINGS 9 Anchorage, Alaska January 13, 2000 9:03 o'clock a.m. APPEARANCES: Commissioners: MR. ROBERT N. CHRISTENSON, CHAIRMAN MS. CAMILLE OECHSLI * * * * * * l11ETRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 .. .. .. ORIGINAL .. .. .. . . 2 1 PRO C E E DIN G S 2 (On record 9:03 a.m.) 3 CHAIRMAN CHRISTENSON: I would like to call 4 this meeting to order. The purpose of the hearing is a request 5 by ARCO on the Point McIntyre/West Beach Oil Pools for request I 6 I authority to initiate miscible gas injection tertiary oil 7 recovery. 8 And it's about a little after 9:00. We are at 3001 9 Porcupine Road, and we will be reconvening the hearing that 10 began yesterday. 11 The Commission will receive both sworn and unsworn 12 testimony. However, in our deliberations, we would like to 13 notify you that you will -- we will give more credit to -- in 14 our deliberations to sworn testimony. 15 This will be recorded, and if you would like a 16 transcription of these proceedings, please contact Metro Court 17 Reporting Company. 18 Persons wishing to testify need to sign in. And 19 there's a list. Cammy's got the list or somebody's got the 20 list here. 21 COMMISSIONER OECHSLI: It's being passed 22 around. 23 CHAIRMAN CHRISTENSON: So please sign in. If 24 you wish to give expert testimony, then please ask us about 25 that and we will listen to your qualifications and then we will METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 3 1 rule on whether it will be admissible as expert witness. 2 After the original presentation, we will accept 3 testimony from those in the public who are present, and we will 4 also accept written testimony. 5 I think that's about it. Oh, the Notice was published 6 in the Anchorage Daily News. I think that was the only paper 7 that we did it in. 8 So I think we are ready for the presentation of the 9 testimony. So, ARCO, would you care to begin and be sworn in, 10 if you so wish? 11 MR. GROTH: Would my name is John Groth. 12 Would you prefer to swear each of us in individually or..... 13 CHAIRMAN CHRISTENSON: Yeah. 14 MR. GROTH: .... .collective? Okay. 15 CHAIRMAN CHRISTENSON: Would you raise your 16 right hand? I 17 (Oath administered) 18 MR. GROTH: I do. !, II 1911 20 II !I II 21 II is 2211 2311 24 !I 2511 [I CHAIRMAN CHRISTENSON: Okay. Please be seated. MR. GROTH: Mr. Chairman, Commissioner, my name John Groth. I am a supervisor with ARCO Alaska. I hold a Bachelors of Science Degree in Chemical Engineering from Rice University. I've been employed by ARCO since 1977 in a variety of positions, and I've supervised the Greater Point McIntyre area development support effort since 1995. I would like to be MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 I. . . 4 1 recognized as an expert witness. 2 CHAIRMAN CHRISTENSON: 3 questions? 4 COMMISSIONER OECHSLI: 5 CHAIRMAN CHRISTENSON: 6 Please proceed. Okay. Do you have any I have no objection. Okay. No objections. 7 MR. GROTH: ARCO Alaska is presenting testimony 8 in support of the application to amend area injection order 9 number 4, and the pool rules for the Point M~and W~st 10 Beach fields. ARCO presents this testimony on behalf of the "'--------- - 11 Point McIntyre working interest owners: ARCO, BP Amoco, and 12 Exxon Corporation, and on behalf of the West Beach working 13 interest owners, ARCO and Exxon. 14 The testimony is divided into four parts. For the 15 Point McIntyre EOR project, John Hand will describe the 16 reservoir engineering aspects, and Murray Athans will describe 17 the facility additions and modifications which are required. 18 For the West Beach water floor project, Carl Lundgren 19 will describe the geologic aspects, and Mike Morgan will 20 describe the reservoir and facility aspects. 21 Each witness is prepared to respond to questions 22 concerning his testimony and related exhibits. For the 23 convenience of the Commission, we have available the text of 24 the testimony and copies of the exhibits. 25 We there is a matter of confidentiality that I would METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 Ia . . 5 1 like to address. There are a number of exhibits -- number of 2 aspects of the West Beach portion of the application, exhibits, 3 and testimony, we plan to give today that contain commercially 4 sensitive confidential information. We believe that this 5 information is useful background information for the 6 Commission, but it's disclosure is not required for the public 7 to understand or comment on the matter before us today. Those 8 items are. In the application dated November 8, 1999, Exhibit 9 F-l, Exhibit F-2; in the supplement dated December 16, 1999, 10 Figures S-4, S-5, S-6, S-7, S-8, S-9; and with regard to 11 today's testimony, the oral testimony of Carl Lundgren; and 12 figures S-10, S-11, and S-12. And we request confidentiality 13 of these items at this time. 14 CHAIRMAN CHRISTENSON: I think before we get to 15 the testimony, we can go into executive session, right? And 16 listen to that. With respect to the items, you will submit 17 II these as confidential? II 18 'I MR . GROTH: The..... 19 CHAIRMAN CHRISTENSON: .... . items right now? 20 MR. GROTH: Yes, we can. 21 CHAIRMAN CHRISTENSON: Okay with you? 22 COMMISSIONER OECHSLI: Yeah. 23 (Off record comments) 24 MR. GROTH: I think we've got a matter with BP 25 folks as well on the West Beach items. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 A.nchorage, Alaska 99501 (907) 276-3876 , . . 6 11 (Off record comments) 2 COMMISSIONER OECHSLI: Do you want to take a 3 break? 4 CHAIRMAN CHRISTENSON: Do you want to take a 5 break to figure this out? Or we can start now. 6 COMMISSIONER OECHSLI: Let me just ask a 7 question. With respect to the order of information, were you 8 going to do the Point McIntyre information all first and then I 9 do West Beach? 10 MR. GROTH: Yes. 11 COMMISSIONER OECHSLI: Do any of these exhibits 12 relate to that? They don't, do they? 13 MR. GROTH: None of these exhibits that we just 14 I 1511 16 \ 1711 I' 18 II II 1911 20 I 21 !I I: 22 II 2311 II 24 II Ii II 2511 I' I ,I :! Ii mentioned relate to the testimony with regard to Point McIntyre. COMMISSIONER OECHSLI: Do you want to do the first part of the Point McIntyre? Do that first and then we can address the West Beach. CHAIRMAN CHRISTENSON: Are you guys set up to do that? MR. GROTH: Yes, we are set up to do that. CHAIRMAN CHRISTENSON: Okay. Why don't we do that. COMMISSIONER OECHSLI: Why don't we do that. MR. GROTH: Okay. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 7 1 CHAIRMAN CHRISTENSON: Let's do Point Mac 2 first. 3 MR. GROTH: Unless there are any other 4 questions at this time..... 5 CHAIRMAN CHRISTENSON: I don't have any. 6 MR. GROTH: .... .1'11 turn the podium over to 7 John Hand. 8 CHAIRMAN CHRISTENSON: Okay. 9 COMMISSIONER OECHSLI: John, do you have copies 10 of all those packages for us? I 111 MR. HAND: Here's the original testimony. 12 CHAIRMAN CHRISTENSON: Do you wish to be sworn 13 in? 14 MR. HAND: Yes. 15 CHAIRMAN CHRISTENSON: Please raise your right 16 hand. 17 181 (Oath administered) MR. HAND: Yes, I do. 191 20 211' 22 II 2311 II 24 II I, 25 II CHAIRMAN CHRISTENSON: Do you wish to be considered an expert witness? MR. HAND: Yes, I do. CHAIRMAN CHRISTENSON: Would you please tell us about your qualifications? MR. HAND: Mr. Chairman, members of the Commission, ladies and gentlemen, my name is John L. Hand. I MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 I f. . . 8 1 am the Subsurface Development Team Leader for the Point 2 McIntyre Field. The Subsurface Development Team is a multi- 3 company, multi-disciplinary team established by the owner 4 companies. This team is responsible for the ongoing reservoir 5 management activities of the Point McIntyre Field. These 6 activities include, but are not limited to, development 7 drilling, reservoir surveillance, production/injection 8 scheduling, and hydrocarbon miscible EOR evaluation and 9 implementation. 10 I received a Bachelors of Engineering Degree in 11 Chemical Engineering with Honors from the University of New 12 South Wales in Sydney, Australia, in 1987, and a Degree of 13 Doctor of Philosophy in Petroleum Engineering also from the 141 I 15 Ii 1611 171 18 II ¡II 19 II II 20 II II 21 II II ,I 22 Ii .1 23 II Ii II 24 !i obj ections? Ii 25 II II University of New South Wales, Sydney, Australia, in 1991. I have been employed by ARCO since 1990 and have worked on a variety of reservoir engineering projects both at ARCO Exploration and Production Technology and ARCO Alaska, Incorporated, as well as a number of field development planning assignments at ARCO Alaska, Incorporated. I worked in the Greater Point McIntyre Area in my current position since September of 1997. I would like to be recognized as an expert witness. CHAIRMAN CHRISTENSON: Do you have any COMMISSIONER OECHSLI: No, I don't. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . . 9 1 CHAIRMAN CHRISTENSON: No objections. Please 2 proceed. 3 MR. HAND: During my testimony today, I will 4 provide information regarding current Point McIntyre field 5 operations as well as the reservoir engineering aspects of the 6 proposed Point McIntyre enhanced oil recovery project. 7 Point McIntyre Pool startup occurred in October of 8 1993. Current operations involve a combination of processed 9 gas reinjection and 80-acre inverted nine-spot pattern 10 waterflooding for pressure maintenance. Gas reinjection into 11 the gas cap began concurrent with field startup, with water 12 injection beginning in July of 1994. As of January 1, 1999, 13 fifteen water injectors and one gas injector provided pressure 14 support to the reservoir, maintaining an average reservoir 15 pressure at the original pressure of approximately 4,370 psi. 16 Source water, from the seawater treatment plant, is currently 17 used for the Point McIntyre waterflood. 18 Point McIntyre production is processed at the Lisburne 19 Production Center, the LPC. Field oil production reached a 20 facility-constrained plateau of 165,000 barrels of oil per day 21 during the second quarter of 1996, and this nominal rate was 22 maintained until the third quarter of 1997. Oil production has' 23 since declined due to increasing water cuts at Point McIntyre 24 and water handling constraints at the LPC. 25 To enhance recovery at oil -- of oil at Point McIntyre, I MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 J&6 .. I I I I 11 I I 2 il I 3 il 'I ;1 I 4 'I 511 II 6 il II 71 8 . . 10 the working interest owners, ARCO, BP Amoco, and Exxon Corporation, have approved a hydrocarbon miscible EOR project. Planned startup for MI injection is the first half of 2000. Exhibit B-1 lS a plat showing the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Point McIntyre Pool as of June 1, 1999. The current Point McIntyre water and potential miscible solvent injector locations are identified in 9 the plat shown in Exhibit B, and are also tabulated in Exhibit 10 B-2. 11 Seventy-four wells have been drilled in Point McIntyre 12 Pool through January 1, 1999, not including P and A'ed wells. 13 The two Point McIntyre drill sites, PM1 and PM2, have 14 production, water injection, and gas lift facilities in place. 15 Drill site ÞM1 also has gas injection facilities in place. 16 Ultimate well count at Point McIntyre is envisioned to be as 17 high as 86 wells, not including P&A'ed wells, depending on the 18 number of 80-acre infill wells and the extent of peripheral 19 development. Present estimates are that drill site PM1 will 20 ultimately have 20 to 23 wells, including four water injectors 21 and one gas injector, and that drill site PM2 will ultimately 22 have 53 to 62 wells, including 10 to 13 water injectors. An 23 additional water injector, Pl-25, is located at the West Dock 24 staging area. 25 All Point McIntyre water injection wells are completed MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh A~·enue. Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ... . . . 11 1 I with L-80 grade steel. All tubing jewelry is completed with 2 Chrome Moly, which is compatible with both L-80 and 13 Chrome. 3 I Point McIntyre water injection completions are designed as a ! 4 single zone, single string with a single packer. Exhibits 8-1 5 through 8-5 show typical wellbore schematics for the five basic 6 well completion designs. 7 The current waterflood pattern configuration for the 8 Point McIntyre Pool is an inverted nine-spot. This pattern 9 selection provides maximum flexibility for potential future 10 conversions to other pattern configurations, as well as in 11 reservoir description and/or -- as changes in reservoir 12 description and/or performance dictate. Additional drilling 13 within the EaR project area may be undertaken to improve sweep 14 in areas of the reservoir unaffected by the hydrocarbon 15 miscible EaR process and to result in the recovery of oil from 16 areas and reservoir volume not otherwise affected by the 17 implemented tertiary recovery activities. Future development I 18 I plans will be based on field performance, including the 191 20 II 2111 II I, 22 II 2311 II I' 24 ,I Ii 'I 2511 II II II I! iI II II II !i performance of the patterns already receiving MI. There are no plans to reduce the well density below 40 acres. A surveillance program to monitor the Point McIntyre EaR flood performance is in place, and is based on experience of operating similar projects at the Prudhoe Bay and Kuparuk Fields. This program will be used to monitor field performance for field management and additional development opportunities. iYETRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 I , . . 12 1 The Point McIntyre EOR project involves the eventual 2 conversion of the existing 15 waterflood injectors, and 3 potentially any future water injectors to water-alternating- 4 gas, or WAG, service. Water will be injected alternatively 5 with MI in the WAG injection wells to improve the MI sweep in 6 the reservoir. At startup of the EOR project, water injection 7 is anticipated to be approximately 250,000 barrels of water a 8 day. Not all of the patterns will be receiving MI 9 simultaneously. THOse patterns not initially converted to WAG 10 injection will remain on continuous water injection until MI is 11 available. 12 Source water is currently used for the Point McIntyre 13 waterflood. It is anticipated that the same injection water 14 will be used during the initial stages of the EOR project. 15 Conversion from source water injection to produced water 16 injection is possible in later stages of the flood. Both of 17 these water sources have been approved for injection into the 18 Point McIntyre reservoir under Area Injection Order 4B. 19 Currently, injection of an MI slug of 35 percent of 20 hydrocarbon pore volume is planned. The maximum size of the MI 21 slug for the project is limited by the rate of delivery of MI 22 manufactured at the LPC. Exhibit S-l shows the relationship 23 between miscible injectant slug size and incremental oil 24 recovery for the Point McIntyre Enhanced Oil Recovery Project. 25 MI generated at the LPC is expected to be delivered to MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 .... . . 13 1 Point McIntyre at a nominal 50 million standard cubic feet per 2 day. Exhibit 8-2 shows the predicted incremental oil 3 production rates for the Point McIntyre Enhanced Oil Recovery 4 Project for the next 23 years for the miscible gas injection 5 rate of 50 million standard cubic feet per day. Exhibit 8-3 6 shows the projected field oil production rates for the Point 7 McIntyre base, primary and secondary, and a base plus EOR for 8 the 50 million standard cubic foot case for this same period. 9 Under the planned scope, the LPC MI supply will be limited, 10 requiring the staging of MI injection into existing patterns as 11 MI becomes available. Initially, two patterns will receive MI 12 injection. As EOR patterns mature, the availability of excess 13 MI will allow additional patterns to begin receiving MI. 14 Nominally, two patterns will be receiving MI at anyone time 15 during the life of the project. It will take around 15 plus 16 years for the last pattern to receive its first MI slug. Peak 17 incremental oil rate is expected to exceed 5,000 barrels per 18 day as a result of the project. 19 Current Point McIntyre operations, processed gas 20 reinjection and pattern waterflooding, are expected to yield an 21 I estimated total recovery of approximately 42 to 45 percent 22 original oil in place for the Point McIntyre Pool. The planned 23 hydrocarbon miscible EOR project at Point McIntyre is estimated 24 to increase oil recovery for an additional 32 million stock 25 tank barrels of oil, or approximately six percent of the MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ~ -\ II II II d 111 211 !i 3 'I Ii . . 14 original oil in place in the current 15 waterflood patterns. The existing waterflood patterns contain varied reservoir quality with incremental oil recovery estimates ranging from four to eight percent of original oil in place of 4 I! ,! 'I !' 'I 5 II 611 il 711 8 , 91 10 II 111 the targeted oil column under a hydrocarbon miscible EaR process. These estimates are based on analysis of core from 20 wells distributed around the field, detailed field wide stratigraphic correlations, PVT and fluid displacement laboratory studies, and fine scale fully compositional fluid flow reservoir simulations tied back to the laboratory data. The fine scale results were subsequently scaled up to the field 12 wide scale, with the estimated incremental oil recovery for the 13 waterflood area determined using the Point McIntyre Full Field 14 reservoir simulation model. 15 MI for the Point McIntyre EaR project will be 16 manufactured at the LPC from a mixture of produced fluids from 17 the Point McIntyre, West Beach, North Prudhoe Bay, Nuyakuk, and 18 Lisburne Pools. Based on the current operating practice of 19 injecting processed natural gas from the LPC into Point 20 McIntyre reservoir, and given that the injected MI comprises 21 the same hydrocarbon components in a more concentrated form, no 22 compatibility problems are anticipated. 23 The miscibility pressure criteria planned for the EaR 24 project is designed to maximize oil recovery and miscible 25 injectant utilization for an MI-limited project. The minimum METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 J í . . 15 1 enrichment level for the Point McIntyre miscible injectant was 2 determined from standard laboratory PVT and slim-tube 3 displacement experiments. The blended MI will have a minimum 4 miscibility pressure of approximately 4,350 psi. The expected 5 composition is given in Exhibit H-l. 6 Injection and production at the Point McIntyre field 7 are managed to maintain the average reservoir pressure at the 8 original reservoir pressure of approximately 4,370 psi. There 9 are no plans to change this reservoir management philosophy. 10 Reservoir pressure monitoring is performed in accordance with 11 Rule 12 of Conservation Order 317A and reported annually to the 12 Alaska Oil and Gas Conservation Commission in the Point 13 McIntyre Oil Pool Annual Reservoir Report. 14 The constant reservoir pressure with temperature along 15 with ne- -- excuse me. The constant reservoir pressure with 16 I time along with negligible temperature variations across the 17 field mean that miscibility pressure requirements are not 18 expected to change as a result of reservoir conditions during 19 the life of the EaR project. Similarly, the compact nature of 20 the Point McIntyre waterflood/EOR patterns exhibit negligible 21 differences in reservoir conditions across the field. The 22 minimum miscibility pressure/minimum miscibility enrichment 23 evaluations for the project were performed at reservoir 24 temperature, 185 degrees Fahrenheit. The thermal temperature 25 bulb at Point McIntyre, due to source water injection, should MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 Ia"- . . 16 1 provide an MMP buffer, but the project design was developed 2 without including this factor. Taken together, these factors 3 reduce the need for a large MMP buffer compared to other North 4 Slope EOR projects. 5 The projected potential maximum miscible injectant rate 6 under the current scope is 70 million standard cubic feet per 7 day. Expanding the Point McIntyre Enhanced Oil Recovery 8 Project by increasing miscible gas injection rate beyond the 9 current scope would require an external source of enriching 10 components for the manufacturing the additional miscible 11 injectant. This is a technically viable option and was part of 12 the initial scoping 13 McIntyre. However, 14 favorable economics studies for an EOR project at Point when this initial evaluation indicated less for this option, subsequent studies focused 15 on self-generating MI project options. These studies resulted 16 in the owner decision to approve the funding of the project 17 described in the testimony today. Analyses to investigate the 18 I benefits of a miscible gas injection rate of up to 150 million 19 I standard cubic feet per day are being evaluated and will be 20 based on the field performance under the current scope. Such a 21 rate would require an external source of enriched miscible 22 injectant, as well as additional drill site facilities and 23 incremental capital expenditures. 24 That concludes my prepared testimony. Thank you. 25 CHAIRMAN CHRISTENSON: Cammy, do you have any METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 17 1 questions? 2 3 4 questions. COMMISSIONER OECHSLI: I don't. CHAIRMAN CHRISTENSON: I've got a couple of With regard to the miscible injectant, you said you 5 don't have as much as you could use. How much more recovery 6 could you get if you had a miscible injectant that you wanted? 7 MR. HAND: When we initially did the screening 8 studies for the Point Mac EOR, we looked at a variety of 9 alternatives. And it was found that there were less -- the 10 expansions were less favorable and so we focused more on the 11 LPC or inhouse MI generating options. From that point on, we 12 followed and developed the technical work based on the scope of 13 the current plan project. We do not really have a -- we did 14 not develop the technical work to a similar caliber for the 15 other cases so we do not really have a similar caliber benefit 16 stream for a larger slug or larger MI volume. But as mentioned 17 in my testimony, we do plan to evaluate that as we get a field 18 I performance back from out initial patterns that we put on MI 19 injection. 20 CHAIRMAN CHRISTENSON: What about -- did you 21 mention early in the testimony that you had limits on the 22 processing capacity, water processing capacity and LPC, that's 23 holding you up as well? Or did I get that wrong? 24 MR. HAND: We talked about -- in the testimony 25 all I talked about was the expected water injection volumes at METRO COURT REPORTING, INC. 550 West Sevemh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 18 1 the time of MI. 21 3 ¡i II 4 il ,I II 5' CHAIRMAN CHRISTENSON: Okay. Well, somewhere I thought I heard that there was a limitation on that. .... MR. HAND: Oh, right. CHAIRMAN CHRISTENSON: . . . . . processing 6 capability. 7 MR. HAND: Right. CHAIRMAN CHRISTENSON: In LPC, right? 8 9 MR. HAND: Right. 10 I CHAIRMAN CHRISTENSON: Are you addressing that 11 in this project? 12 MR. HAND: I I feel that pro- -- I'm 13 probably not the best person to answer that question. Maybe 14 Murray Athans will be able to answer that when he talks about 15 the facility -- facilities at Point McIntyre or the LPC in 16 relation to this project. 17 CHAIRMAN CHRISTENSON: Okay. So what you're 18 going to do is In the initial phases, you're going to see how 19 effective this MI is under the current project, and then you/II 20 evaluate whether it would be advantageous to acquire additional 21 MI for -- if it looks like that would be cost-effective. Is 22 that correct? 23 MR. HAND: That is correct. That is correct. 24 CHAIRMAN CHRISTENSON: But any of that would 25 have to come from another facility. Have I got that right? MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh A~'enue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 19 1 MR. HAND: Yes. We would acquire an external 2 source of miscible injectant or enriched hydrocarbon components 3 to make miscible injectant. Yes. 4 5 Cammy? 6 7 8 9 10 Athans. 11 CHAIRMAN CHRISTENSON: Thanks. Anything else, COMMISSIONER OECHSLI: I don't. CHAIRMAN CHRISTENSON: Thank you very much. MR. HAND: Thank you. MR. ATHANS: Good morning. My name is Murray CHAIRMAN CHRISTENSON: Would you like to be 12 sworn in, sir? 13 MR. ATHANS: Yes, I would. 14 15 hand. 16 17 CHAIRMAN CHRISTENSON: Please raise your right (Oath administered) MR. ATHANS: I do. 18 CHAIRMAN CHRISTENSON: Do you wish to be 19 considered an expert witness? 20 MR. ATHANS: Yes, I do. 21 CHAIRMAN CHRISTENSON: Would you present your 22 qualifications, please? 23 MR. ATHANS: Mr. Chairman, members of the 24 Commission, ladies and gentlemen, my name is Murray P. Athans. 25 I am the ARCO Project Engineer for the Point McIntyre EOR MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 20 1 project. In this role, my job ~esponsibilities have included 2 facility design, oversight and review, and acting as the 3 primary coordinator between the engineering contractor and the 4 Lisburne Production Center, LPC, Operations Team. It has been 5 my job to insure that the new facilities are fit for their 6 intended purpose, are built to ARCO Alaska standards, and meet 7 all operating and safety design requirements. 8 I received a Bachelors of Science Degree with Honors in 9 Chemical Engineering from the University of Texas at Austin in 10 1978, and a Masters of Science Degree in Chemical Engineering 11 from the University of Texas at Austin in 1980. I began work 12 for ARCO at the Exploration and Production Research Center in 13 PIano, Texas, in 1980, then transferred to ARCO Alaska in 1984. 14 Since arriving in Alaska, I have worked In a broad variety of 15 facility planning and process engineering positions within the 16 Prudhoe Bay and Kuparuk business units. I transferred into the 17 Greater Point McIntyre Area in August 1997, at which time I 18 began my current assignment as Project Engineer for the Point 19 McIntyre EOR project. 20 I would like to be recognized as an expert witness. 21 CHAIRMAN CHRISTENSON: Thank you. 22 COMMISSIONER OECHSLI: I have no objection. 23 CHAIRMAN CHRISTENSON: No objection. Please 24 proceed. 25 MR. ATHANS: Okay. During my testimony today, MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 21 1 I will provide an overview of the facility modifications and 2 additions which are being installed to implement the Point 3 McIntyre EOR project. I will also briefly discuss some of the 4 project facility considerations that impacted the miscible 5 injectant rate projections previously discussed by John Hand. 6 Vapors generated in the LPC NGL, natural gas liquids, 7 plant downstream from the feed flash drum, which are currently 8 being injected as residue gas, will provide the enriching 9 components for the MI solvent stream. Facility modifications 10 are designed to ensure that the volume of blendable NGLs 11 extracted at the LPC will not be impacted by the EOR project. 12 Manufacture of MI at the LPC at a greater rate than planned for 13 the project would adversely impact NGL production. 14 The nominal annual average MI manufacturer rate is 15 expected to be 50 million cubic feet per day. During the 16 summer months, we expect to see an MI manufacture rate lower 17 I than winter months due to reduced NGL refrigeration capacity 18 resulting from higher ambient temperatures. In the first four 19 to five years of the project, MI rates during the summer are 20 expected to range between 42 to 45 million cubic feet per day, 21 while in the winter ranging between 52 to 53 million cubic feet 22 per day. After four to five years, MI rates should be consistently in the 50 million cubic feet range, with peaks as 23 , II 24 'I II 2511 Ii II II II !I Ii high as 60 to 70 million cubic feet per day. Peak rates -- peak rate estimates are based in part on predictions of the MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 11 ,I 1 II II 211 II 3 II , " 4 'ii II 11 51 61 II 71 8 . . 22 volumes of return miscible injectant, MI. The primary factors limiting the amount of MI manufacture at LPC are the LPC piping and vessel metallurgical limit of minus 50 degrees Fahrenheit, per ASME codes, and the plant refrigeration capacity. The new chiller installed as part of the project was sized to utilize the existing excess refrigeration capacity, propane system, at the LPC. Increasing refrigeration capacity would require significant incremental 9 capital. I 10 Modifications at the LPC during 1999 and early 2000 in 11 support of the Point McIntyre EOR project include the 12 installation of an MI compressor, a second chiller, new compressor coolers and blending station, and an upgrade of the 13 14[ 151[ 16[1 17/1 Ii 18 II ¡i 19 II iI Ii 20 II 1\ I. 211' II '" 22 ji II 23 I' ,I LPC NGL plant liquid piping. MI will be transported to the Point Mac drill sites via a new distribution pipeline shown in Exhibit A-I using currently installed vertical support members. The EOR project will also require installation of drill site distribution piping. Hydrogen sulfide, H2S concentrations, during the life of the project are expected to remain low. The equipment being installed is designed to handle the expected HzS concentrations. We will continue to observe existing H2S safety precautions. Ii Ii 24 i! The estimated maximum and average injection pressures 25 anticipated for the Point McIntyre enhanced recovery projects METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · i. 23 1 are listed in the following table. These pressures represent 2 pump discharge pressures. 3 The estimated maximum injection rates for Point 4 McIntyre enhanced recovery wells will not initiate or propagate 5 fractures through the confining strata, and, therefore, will 6 not allow injection or formation fluid to enter any freshwater 7 strata. All field data collected to date indicate that 8 injection in the current water injectors and the single gas 9 injector at Point McIntyre has been confined to the injection 10 strata. It is our expectation that the injected MI will remain 11 confined to the injection strata. 12 Existing water injection operations in the Point 13 McIntyre Pool Kuparuk River Formation have been above formation 14 parting pressure to improve recovery of oil. In no instance 15 have such injection pressures breached the integrity of the 16 confining zone. 17 This concludes my testimony. 18 CHAIRMAN CHRISTENSON: Cammy, do you have any 19 questions? 20 COMMISSIONER OECHSLI: I don't. 21 CHAIRMAN CHRISTENSON: Could you answer the , 22 question with regard to the limit on the facilities? 23 MR. ATHANS: Yes. Again, as I discuss in here, 24 there are basically two primary factors that limit our MI rate 25 to about the 50 million cubic foot per day number. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 24 1 And, again, the first one is our metallurgical 2 temperature limit on our piping. All of our piping is only 3 rated by code down to minus 50 degrees Fahrenheit. So per 4 code, we cannot go below minus 50 on the piping. You know, 5 safety issue. 6 And then secondly is we had some excess propane 7 refrigeration capacity at the LPC already existing. And what 8 we did with this project was we added a second chiller to 9 basically, you know, use up that excess capacity so that we've 10 sized that chiller such that it will efficiently use the rest 11 of our capacity. 12 And so basically those are the two things, our 13 metallurgical temperature limit, and then now we are using up 14 151 all the excess capacity. To go beyond that would have required very significant capital cost additions which we didn't judge 16 to be economic. So those are the two primary factors that 17 limit our rate. 18 CHAIRMAN CHRISTENSON: Is there anything else 19 that limits your rate? Is there a water handling problem? 20 MR. ATHANS: No. Water handling really I 21 mean that may limit our production rate but that really doesn't 22 affect the MI rate. 23 CHAIRMAN CHRISTENSON: I know but does it 24 affect the rate of this EOR project? 25 MR. ATHANS: No. No, because we're already -- METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · i. 25 1 you know, we already have -- that really doesn't affect the 2 amount of the MI components that we're going to be able to 3 remove again. The temperature limits and the refrigeration 4 limits are really what affect that, and water is really a 5 separate issue. 6 MR. GROTH: May I? 7 CHAIRMAN CHRISTENSON: Yeah, John. 8 MR. GROTH: To the extent that, you know, water 9 handl ing . . . . . 10 (Witness walks up to microphone) 11 MR. GROTH: To the extent that the water 12 handling capacity in and of itself has an effect upon the 13 recovery for the EOR project, the answer would be limited. But 14 to the extent the water handling capacity in and of itself has 15 an impact on the ability of all of the fields within the 16 Lisburne GPMA production system to produce, if you've got a 17 higher water handling capacity within the plant, well, yes. 18 There would be a higher through put rate associated with all 19 I the fields, and there would be instantaneous increases in 20 ~ production associated with that. 2111 CHAIRMAN CHRISTENSON: So it does have an 2211 overall effect then in - - I mean you could produce more if you II 23 II had more water handling capacity? 2 4 i,l 0 O· b . il MR. GR TH: n an lnstantaneous aS1S, yes. ¡I i 25 II ii MR. ATHANS: It starts to get pretty technical METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 26 i I 1 i though because if we're all -- I think what John is saying is I 211 we could produce more total gas if we could also produce more 3 II total oil but, again, it really begins to get complex then as 4 Ii to whether if we're already using all of our refrigeration 511 'I I! 6 i! I' d capacity, those few extra components that we would bring in with the gas, you mayor may not, depending on where you are in 7 r the life of the project, be able to capture those and 8 I efficiently use those. So it's not a, you know -- I don't 9 think the affect is large at all. The fact that, you know, if 10 we had a little more water handling capacity, I don't think you 11 would see a tremendous increase in the MI rate. 12 CHAIRMAN CHRISTENSON: Okay. Thanks. 13 MR. GROTH: That does conclude our testimony 14 for the Point McIntyre portion of the application. 15 CHAIRMAN CHRISTENSON: Okay. Thank you. 16 COMMISSIONER OECHSLI: Do you want to take a 17 break at this point? 18 CHAIRMAN CHRISTENSON: Yeah. Let's take a 10 19 minute break at this point, then we'll reconvene. (Off record 9:42 a. m.) (On record 10:08 a. m.) CHAIRMAN CHRISTENSON: Let's reconvene. John, 20 21 22 23 we have one more question that came up in our discussions. It 24 relates to the buffer between MMP and reservoir pressure. And 25 we would like to know what you all think the in terms of METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · '. 27 1 some general parameter there how much that temperature is going 2 to affect that buffer. You're talking about 20 psi between MMP 3 and reservoir pressure. And then you also talked about how the I 4 temperature was gOlng to give you a wider margin. We would 5 like to hear your comments on what you think that's going to 61 be, how much help you're going to get out of that? And our 7 reasons are because we've heard a lot in other discussions with 8 regard to that where you're looking at a 100 to 150 psi buffer. 9 MR. HAND: The average reservoir pressure that 10 we try and maintain the reservoir at, we talk about is a normal 11 4370. We take pressures every year and report that to the 12 Commission, and other than the first eight months of production 13 which we were not -- didn't have any water injection, we've 14 actually probably normally kept it above that. And we monitor 15 that pressure every year. We report that every year and 16 monitor our pressure, with sag bottom hole pressures or flowing 17 bottom hole pressures, right throughout the year. So it 18 generally is a little higher than 4370 so that press- that 19 type of pressure buffer is a little higher. 20 With regards to the temperature effect, the lower 21 temperature reduces the requirement of enrichment and so, 22 therefore, gives a larger effective minimum miscibility 23 pressure buffer. We -- I could -- at this point in time, I 24 could not give you the exact number of what that buffer would 25 be. We can get -- we can report back to you on that if METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · '. 28 1 required. 2 CHAIRMAN CHRISTENSON: I don't think we're so 3 much interested in a specific number as sort of a range. What 4 do you expect to get in terms of overall benefit out of that? 5 MR. HAND: You would..... 6 CHAIRMAN CHRISTENSON: Because you said 7 you..... 8 MR. HAND: You would get a -- for the given 9 enrichment we have, it would essentially represent a slight 10 overenrichment of the MI. And so it would be less of a concern 11 of losing miscibility. It basically is essentially the same 12 affect as increasing the pressure buffer that you have in the 13 field. So your miscibility will be met. You have less concern 14 about losing miscibility. 15 CHAIRMAN CHRISTENSON: Yeah. Can you 16 equivocate that to -- is that like going to be like a 50 psi 17 buffer or a 100 psi buffer or what? 18 MR. HAND: I really couldn't..... 191 CHAIRMAN CHRISTENSON: We're not looking for 20 specific numbers here. 21 MR. HAND: Yeah. 22 CHAIRMAN CHRISTENSON: Just if you could give 23 us an idea so we would have some idea relative to other things 24 we know about. 25 MR. HAND: I really couldn't glve you a METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 29 1 definite answer on that. I would have to get back to you on 2 that one. 3 CHAIRMAN CHRISTENSON: That's fine. 4 MR. HAND: I will calculate that for you. 5 CHAIRMAN CHRISTENSON: Okay. Do we have any 6 other questions? 7 COMMISSIONER OECHSLI: No. 8 CHAIRMAN CHRISTENSON: All right. John. 9 MR. GROTH: May I -- one -- I guess a couple 10 points of clarification on the water handling capacity 11 question. I think we've got amongst ourselves a better 12 understanding of what you were driving for there. 13 The facility limits at the LPC are integrated and have 14 implications upon each other. So you can have gas handling 15 constraints. You can have water handling constraints. Within 16 the GPMA system, there may be hydraulic constraints within 17 certain common lines that feed into the LPC. We tend to look 18 at that system as a whole. And in the past, water handling has 19 been a constraint. Gas handling may have been a constraint. 20 Oil processing capacity within the system has been a 21 constraint. Those are things that we have looked at and will .1 221! 23 I I I continue to look at to see if there are opportunities to de- bottleneck those. With the initiation of miscible injectant 24 operations, that's another constraint that is now into the 25 i system but it will be integrated and will be part of our METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 "-inchorage, Alaska 99501 (907) 276-3876 . . 30 1 ongoing evaluations to see if there are any opportunities to 2 de-bottleneck the system as appropriate. 3 CHAIRMAN CHRISTENSON: I noted that you said 4 instantaneous value. So I guess the implication of that is 5 that you don't expect even if you would find some things you 6 wouldn't expect an increase in overall recovery. It just 7 it's a timing 8 get it later. 9 situation whether you get it now or whether you MR. GROTH: I think there are elements of 10 additional recovery that may come with a particular de- 11 bottlenecking opportunity. But we look at both the 12 instantaneous rate benefit and the additional recovery benefits 13 associated with those to determine if that particular 14 opportunity is economical. But the instantaneous rate benefit 15 associated with those typically is a -- the larger portion of 16 the benefits. 17 CHAIRMAN CHRISTENSON: I think that clears it 18 up for us. Let's see, at this time, is there any public 19 testimony with regard to Greater Point Mac? We're going to try 20 to split this up into the confidential and non-confidential 21 issues. So we would like to wash out the Point Mac question. 22 Are there any other testimonies or comments with regard to 23 Point Mac? And then we'll move on to the confidential session. 24 Seeing none, we need to go into confidential session. 25 So, John, do you want to help me out here and see who would METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 31 1 need to -- besides Kristen. Are there others? Thank you, 2 Kristen. 3 2884 4 5 4415 6 7 8 9 Morgan. 10 (Meeting adjourned to go into executive session) (Public hearing reconvened) CHAIRMAN CHRISTENSON: Good morning. MR. MORGAN: Good morning. My name is Michael I would like to be sworn in. CHAIRMAN CHRISTENSON: Okay, sir. Raise your 11 right hand. 12 (Oath administered) 13 MR. MORGAN: I do. 14 CHAIRMAN CHRISTENSON: Do you wish to be 15 considered an expert witness? 16 MR. MORGAN: Yes, I do. 17 CHAIRMAN CHRISTENSON: Okay. Would you proceed 18 with your qualifications? 19 MR. MORGAN: Mr. Chairman, members of the 20 Commission, ladies and gentlemen, my name is Michael R. Morgan. 21 I am a Staff Petroleum Engineer with ARCO Alaska. I received a 22 Bachelors of Science Degree in Petroleum Engineering from the 23 Colorado School of Mines in 1986. I have been employed by ARCO 24 since 1986, and have worked a variety of engineering projects. 25 I have worked in the Greater Point McIntyre Area on West Beach METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 32 1 Pool development since February 1996. 2 I would like to be recognized as an expert witness. 3 41 any.... . 5 6 7 proceed. 8 CHAIRMAN CHRISTENSON: Cammy, do you have COMMISSIONER OECHSLI: No objection. CHAIRMAN CHRISTENSON: No objections. Please MR. MORGAN: Okay. During my testimony today, 9 I will provide information regarding West Beach operations and 10 the engineering aspects of the proposed West Beach Secondary 11 Recovery Project. 12 (Off record comments) 13 West Beach Pool startup occurred in April 1993. The 14 field has been delineated by 11 penetrations consisting of 15 seven wells and four sidetracks. Three wells currently are 16 active: West Beach 4, West Beach 5B, and West Beach 6. 17 Exhibit B-3 is a plat showing the location of West Beach area 18 I wells, including the three active wells, which are West 19 Beach 4, 5B, and 6. Our recent efforts have focused on 20 delineation and further development of the West Beach 21 reservoir, development of a secondary recovery plan, and 22 construction of additional surface infrastructure to handle 23 anticipated additional production from the West Beach 24 reservoir. 25 Secondary recovery plans at West Beach include water MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 33 1 injection utilizing locally sourced water from Tertiary sands 2 produced from a new well on the West Beach Pad. Reservoir 3 simulation studies indicate incremental recovery from water 4 flooding to be between 10 to 15 percent of the estimated 15 to 5 25 million stock tank barrels of oil originally in place. 6 Augmenting water injection with gas injection to capture attic 7 oil along the southern fault trap is also being evaluated. 8 Thus, our application requests authorization for both water and 9 gas injection to enhance recovery from the West Beach 10 reservoir. 11 The West Beach geologic model was updated in early 1998 12 to incorporate data from the West Beach 5 and West Beach 6 13 wells. Utilizing this new geologic description and available 14 data from area production and exploration wells, a detailed 15 reservoir simulation model was constructed. The objectives of 16 the model study were to screen potential development or 17 delineation well locations and to evaluate secondary recovery 18 options. Results from the study indicate a peripheral 191 waterflood injecting into West Beach 6, which is the well down 20 to the -- getting backwards here. Right there. And producing 21 !I II 2211 i 23 1 I 2411 2511 ¡I II ''I from the updip, West Beach 4 and West Beach 5B as a preferred development scenario, with estimated incremental recovery of 10 to 15 percent of the original oil in place. The modeling study indicated that increased well density primarily tended to accelerate the base reserve profile, with little incremental METRO COURT REPORTING, INC. 550 West Seventh A~'elIue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 34 1 recovery. However, waterflood performance data will be key to 2 assessing additional development potential at West Beach. 3 Currently the minimum well spacing is 80 acres which should 4 be -- which should accommodate potential future drilling at 5 West Beach. 6 Recent drilling production and surveillance data from 7 West Beach 4, 5B, and 6 have validated the modeling study and 8 volumetrics. Post-fracture peak production from both West 9 Beach 5 and West Beach 6 was initiated at 1,700 stock tank 10 barrels of oil per day and 2,500 stock tank barrels of oil per 11 day, respectively. Subsequently, production in West Beach SB 12 has fallen to 830 stock tank barrels of oil per day, primarily 13 due to reduced reservoir pressures in the area due to the 14 i 15 II II 16 II Ii 1711 Ii .1 18 II II p 19 il :i II 20 I! " i! II 21 :1 :ii Ii 22 II Ii II 23 Ii increased offtake. The lower well rates and solution GOR of West Beach 5B make it difficult to keep this well online due to paraffin build-up associated with cold flowing temperatures. Production from West Beach 6 is currently at 800 stock tank barrels of oil per day with associated gas of 11.2 million standard cubic feet per day. Reservoir pressure monitoring indicates good connectivity between the wells as evidenced by the pressure drop of 500 to 750 psi following sustained production from all three wells. These pressure drops are consistent with the reservoir model and confirm lateral 24 connectivity between the wells. Lack of connectivity is a key 25 risk to secondary recovery at West Beach. MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh A~'enue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 35 1 The West Beach waterflood involves conversion of West 2 Beach 6 to injection service in the first quarter of 2000. The 3 conversion will be conducted In accordance with Alaska 4 Administrative Code. Can everybody see that? The West Beach 7 5 source water well, permit number 199-106, will supply injection 6 water with an electrical submersible pump producing water from 7 the Tertiary sands at a maximum rate of 10,000 barrels of water 8 per day and 2,100 psi surface pressure. This source water well 9 is currently being drilled. Exhibit E-1 shows the planned 10 potential completion intervals on the West Beach 1 shallow 11 section log, this section here. A local water sample from the 12 target water source interval has not been obtained. However, 13 it is anticipated the water will be of similar composition to 14 that produced from the GC-3 water wells as shown in Exhibit M-1 15 from the April 5, 1993, Application for Modification to Area I 16 Injection Order Number 4. Electric log salinity calculations 17 from West Beach State 1 indicates salinities of 20 to 40,000 18 ppm, which are consistent with the GC-3 water sample analyses 19 and previous log calculations. 20 Laboratory testing, core analyses, and geochemical 21 modeling indicate no significant problems with clay swelling or 22 in-situ fluid compatibility. Analysis of a sample of West 23 Beach 4 core in a lower quality interval indicates significant 24 amounts of clay, 11 percent, may be present, primarily in the 25 form of Kaolinite. The presence of this clay may cause pore MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 36 1 plugging in conventional unstimulated producing wells at 2 waterflood breakthrough. However, both West Beach producing 3 wells are hydraulically fracture treated which will minimize 4 fluid velocities and subsequent fines movement in the rock near 5 the producing wells and thus minimize the potential for 6 producing well formation damage. Calculations for West Beach 4 7 show the velocities are 280 times less for the fractured 8 completion compared to an unstimulated completion. No evidence 9 of fines migration was observed during the initial post-frac 10 clean up tests in any of the wells at West Beach. 11 The Tertiary water is expected to contain excess barium 12 at concentrations from 50 to in excess of 300 parts per 13 million. If uninhibited, barium sulfate scale could result 14 when West Beach produced water is mixed with Point McIntyre 15 produced water containing excess sulfate associated with 16 seawater breakthrough. However, the West Beach produced water I 17 I stream will be inhibited upstream of the Point McIntyre/West 18 I Beach commingling point to prevent barium sulfate I 19 I precipitation. Because West Beach has not produced any I 20 II formation water, reservoir compatibility modeling and I 21 laboratory testing assumed a water composition similar to that 22 of Point McIntyre. 23 Initially, the waterflood will be managed to replace 24 reservoir voidage. As the flood progresses, injection rates 25 will be adjusted in response to producing well surveillance and METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · ¡. 37 1 performance. 2 New facilities installed and in service on the West 3 I Beach Pad include a central manifold designed to collect I 4 production from four initial wells and five additional wells. 5 The pad will also have a new chemical injection skid and a new 6 electrical distribution skid. A new 12 inch pipeline has been 7 installed from the West Beach pad to drill site Ll to handle 8 the increased production rates. Additionally, a four inch high 9 pressure line has been installed that will be used to supply 10 lift gas to the pad. The line has been designed to accommodate 11 high pressure gas or miscible injectant if additional pressure 12 maintenance or tertiary recovery can be justified. The 13 existing six inch production line will be converted to a 14 dedicated test line. 15 To facilitate initiating production from the West 16 Beach 5B and 6 wells, design and material procurement for the 17 facility expansion occurred prior to drilling the wells. 18 Consequently, sizing considered the low incremental cost for 19 additional slots and various future development scenarios, 20 including potential additional drilling for West Beach or other 21 GPMA fields. Waterflood performance data will be key to 22 assessing additional development potential at West Beach. 23 That concludes my testimony. 24 CHAIRMAN CHRISTENSON: Mike, I think I missed 25 it in the first part. How many wells did you say you were METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · i. 38 1 going intended to drill, additional wells? 2 MR. MORGAN: Right now, we're -- we have no 3 plans to drill additional wells until we get some response from 4 the waterflood. And at that point, we will re-evaluate our 5 plans for the field. 6 CHAIRMAN CHRISTENSON: Okay. Gotcha. Thank 7 you. No further questions. 8 MR. MORGAN: Thank you. 9 MR. GROTH: That concludes our testimony for 10 the West Beach portion of the application. 11 CHAIRMAN CHRISTENSON: Okay, sir. Thank you. 12 Any further comments from the public with regard to the West 13 Beach? Do you want to take a break? 14 COMMISSIONER OECHSLI: Sure. 15 CHAIRMAN CHRISTENSON: We're going to go off 16 record here for about 10 minutes to do some deliberation, make 17 sure we got all the questions. So if you would excuse us. 18 (Off record 11:00 a.m.) 19 (On record 11:12 a.m.) 20 CHAIRMAN CHRISTENSON: We back on record? 21 We've got a couple of questions -- further questions. 22 General questions we would like you to answer -- I'll 23 just tell you what the questions are, then you guys can figure 24 out who you want to answer them. 25 Question one. Are you planning to maintain voidage? MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 39 1 Question two. What are the initial and current reservoir 2 pressures? And we would like you to elaborate a bit more on 3 the paraffin build-up and any mitigation plans you might haver 4 and your concerns there. 5 MR. MORGAN: I think that's me. 6 CHAIRMAN CHRISTENSON: Okay. Mike. 7 MR. MORGAN: Regarding question one 8 actually, if you could repeat it for me so I make sure I get 9 them in the right order there. 10 CHAIRMAN CHRISTENSON: Question one was are you 11 planning to maintain voidage? Because you -- or make up 12 voidage because you had talked about it staying the same or 13 doing something like that and so we wondered if you were going 14 to -- did that meant that you were making it up or are you just 15 going to maintain what you're doing or where are you in the 16 voidage picture? 17 MR. MORGAN: I guess that's our initial 18 strategy is to replace voidage but I think right up front, I 19 I given that we're at, depending on which well you measure the 20 pressure in, anywhere from 3rOOO -- just above 3,000 pounds to 21 3,300 pounds we will exceed voidage from the wells, especially 22 given West Beach 5 is not on line. 23 CHAIRMAN CHRISTENSON: So you will actually 24 make up and exceed that..... 25 MR. MORGAN: Yeah. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 40 1 CHAIRMAN CHRISTENSON: . . . . . ul timately? 2 MR. MORGAN: And I guess that leads into 3 question two which speaks to the initial pressures and current 4 I pressures. Initial pressures were measured in West Beach 4, I 5 and this is roughly a number. I don't have the number in front 6 of me but we've provided it in various formats, around 4,250 7 psi in West Beach 4. Stand alone production from that well 8 through this year drew the reservoir pressure down to about 9 3,500 pounds. And then we brought on West Beach 5B and West 10 Beach 6 in July and August of 1999, and by November, we had 11 seen the pressure fall in West Beach 5B which is in the updip 12 area to just above 3,000 psi. And then also at West Beach 6, 13 it was down around 3,300 pounds. 14 CHAIRMAN CHRISTENSON: Okay. 15 MR. MORGAN: And that data was submitted for 16 the code. But what we will do is we will go ahead and start up 17 the pump and inject at voidage and see if we see an initial 18 response because we do have gas in the system. We don't want 19 to overdisplace the oil. 20 CHAIRMAN CHRISTENSON: Okay. Then the last 21 question was you made some mention of the paraffin build-up in 22 one of the wells, and we're curious about what the effect you 23 think that's -- the new injection is going to have on that. Is 24 that a problem? 25 MR. MORGAN: The paraffin we see, we have seen METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · Ie 41 1 it historically in West Beach 4 but it's become severe in West 2 Beach 5B. I don't have a schematic but that well is basically 3 a 16,000 foot measured depth well with tubing down to about 4 13,800. It's three and a half inch tubing. We do have lift 5 gas out to the well. Initially, at the 1,700 barrel a day 6 I rates, it was fine. And with even a small water cut associated 7 with the fracture treatment, we were able -- we didn't have too 8 many paraffin problems but as the reservoir pressure declined 9 and the rates in the well dropped pretty low down to around 800 10 barrels a day, we get severe paraffin build-up throughout that 11 tubing to the point where it plugs off and we have to go out 12 with coil tubing and clean it up. And so that's just a cost 13 that we incur. What we expect, if -- when we get waterflood 14 response from West Beach 6, is that the pressure will start to 15 corne back up and that we will be able to sustain production 16 from that well. That's the current plan. 17 CHAIRMAN CHRISTENSON: Okay. 18 MR. MORGAN: It's similar to other wells at 19 Point McIntyre and Nuyakuk that you get to those rates in these 20 high departure wells. Temperatures drop pretty low. 21 CHAIRMAN CHRISTENSON: 22 have any further questions? 23 COMMISSIONER OECHSLI: 24 CHAIRMAN CHRISTENSON: 25 up on the question area. Okay. Cammy, do you I don't. Thanks. I think that cleans us MET ROC 0 V R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · I. 42 I 11 I 21 I! 3 II I' 411 II 5 II 6 !I 7 MR. MORGAN: One other point I would like to make regarding the operation of the flood is our intent is to operate the flood to increase pressures up towards 3,800 psi. And we think that's an optimal point for the field. So prior to that, we'll probably exceed voidage replacement. So it will be above one on the VRR ratio. CHAIRMAN CHRISTENSON: So your target is 3,800 8 then? 9 10 11 12 13 clarification. 14 MR. MORGAN: Yeah. CHAIRMAN CHRISTENSON: Great. Thank you. MR. MORGAN: You're welcome. MR. GROTH: If I may, one other point of CHAIRMAN CHRISTENSON: Sure. 15 MR. GROTH: In our prepared testimony, we had 16 mentioned a maximum injection rate of 10,000 barrels a day. 17 That is, in fact, the name plate capacity on the pump equipment 18 that we are planning to install. In the event that we see 19 better than expected pump performance, we would ask that we 20 have a maximum injection rate 15,000 barrels a day that the 21 Commission consider that so that we're not back in here shortly 22 soon after start up requesting another amendment. 23 CHAIRMAN CHRISTENSON: Okay. So you want to 24 change or expand I guess the injection rate from 10 to IS? 25 MR. GROTH: To 15 so that we've got some head MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 · '. 43 1 room for daily operations above name plate capacity on the 2 equipment. 3 CHAIRMAN CHRISTENSON: We'll look at that. I 4 guess one point of clarification we have to do on this 5 confidential thing, too. We are understanding the 2003 date 6 and the information contained in those items we talked about 7 there, to be only those items, and we're not going to 8 retrograde back into other stuff that's already happened and 9 records and stuff that we already have. And is that your 10 understanding? 11 MR. GROTH: We concur with that understanding. 12 CHAIRMAN CHRISTENSON: Okay. Good. Is there 13 any other testimony or comments to be made today with regard to 14 West Beach? No. Cammy, do you have anything else? 15 COMMISSIONER OECHSLI: I don't. 16 II CHAIRMAN CHRISTENSON: I think we've completed I 17 it. And I would like to thank you for corning in and making a 18 presentation. All good presentations. We appreciate the 19 information. And that concludes our hearing for today. We'll 20 adjourn. Thank you. 21 (Off record 11:18 a.m.) 22 END OF PROCEEDINGS 23 24 25 JJ1ETRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 . . 44 1 C E R T I FIe ATE 2 UNITED STATES OF AMERICA) )ss. snrn OFA~SAA ) 3 4 I, Laura Ferro, Notary Public in and for the State of 5 Alaska, and Reporter for Metro Court Reporting, do hereby 6 certify: 7 That the foregoing Alaska Oil & Gas Conservation 8 Commission Public Hearing, was taken before me on the 13th day 9 of January 2000, commencing at the hour of 9:03 o'clock a.m., 10 at the offices of Alaska Oil & Gas Conservation Commission, 11 3001 Porcupine Street, Anchorage, Alaska; 12 That the hearing was transcribed by me to the best of 13 my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and 14 15 affixed my seal this 18th day of January 2000. No~~or Alaska My commission expires: 05/03/01 16 17 18 19 20 21 22 23 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ~ . . . " . Pt. Mcintyre Oil Pool Enhanced Oil Recovery Project West Beach Oil Pool Secondary Recovery Project Application for Injection and Amendmènt to Area Injection Order No. 4B pt. Mcintyre Testimony January 13, 2000 January 13. 2000 . . Table of Contents Section A - Testimony of John L. Hand ......................................................................................1 Section B - Testimony of Murray P. Athans................................................................................4 Pt. Mcintyre EOR Project Application - Testimony . . Section A - Testimony of John L. Hand Mr. Chairman, members of the commission, ladies and gentlemen, my name is John L. Hand. I am the Subsurface Development Team Leader for the Pt. Mcintyre Field. The Subsurface Development Team is a multi-company, multi-disciplinary team established by the owner companies. This team is responsible for the ongoing reservoir management activities of the Pt. Mcintyre Field. These activities include, but are not limited to, development drilling, reservoir surveillance, production/injection scheduling, and hydrocarbon miscible EOR evaluation and implementation. I received a Bachelors of Engineering Degree in Chemical Engineering with Honors from the University of New South Wales, Sydney Australia, in 1987 and a Degree of Doctor of Philosophy in Petroleum Engineering also from the University of New South Wales, Sydney Australia, in 1991. I have been employed by ARCO since 1990 and have worked on a variety of reservoir engineering projects both at ARCO Exploration and Production Technology and ARCO Alaska, Inc., as well as a number of field development planning assignments at ARCO Alaska, Inc. I have worked in the Greater Pt. Mcintyre Area in my current position since September, 1997. I would like to be recognized as an expert witness. During my testimony today I will provide information regarding current Pt. Mcintyre field operations as well as the reservoir engineering aspects of the proposed Pt. Mcintyre enhanced oil recovery project. Pt. Mcintyre Pool startup occurred in October 1993. Current operations involve a combination of processed gas reinjection and 80-acre inverted nine-spot pattern waterflooding for pressure maintenance. Gas reinjection into the gas cap began concurrent with field startup, with water injection beginning in July of 1994. As of January 1, 1999, fifteen water injectors and one gas injector provide pressure support to the reservoir, maintaining average reservoir pressure at the original pressure of approximately 4370 psi. Source water, from the Seawater Treatment Plant, is currently used for the Pt. Mcintyre waterflood. Pt. Mcintyre production is processed at the Lisburne Production Center (LPG). Field oil production reached a facility-constrained plateau of 165,000 BOPD during the second quarter of 1996 and this nominal rate was maintained until the third quarter of 1997. Oil production has since declined due to increasing water cuts at Pt. Mcintyre and water handling constraints at the LPC. To enhance recovery of oil at Pt. Mcintyre, the Working Interest Owners (ARCO, BPA and Exxon) have approved a hydrocarbon miscible EOR project. Planned startup for MI injection is the first half of 2000. Exhibit B-1 is a plat showing the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Pt. Mcintyre Pool as of June 1, 1999. The current Pt. Mcintyre water and potential miscible solvent injector locations are identified in the plat shown in Exhibit B-1 and are tabulated in Exhibit B-2. Seventy-four wells have been drilled in the Pt. Mcintyre pool through January 1, 1999 (not including P&A'ed wells). The two Pt. Mcintyre drill sites, PM1 and PM2, have production, water injection, and gas lift facilities in place. Drill site PM1 also has gas injection facilities in place. Ultimate well count at Pt. Mcintyre is envisioned to be as high as 86 wells (not including P&A'ed wells), depending on the number of 80-acre infill wells and the extent of peripheral development. Present estimates are that DS-PM1 will ultimately have 20-23 wells, including four water injectors --- ...--- ---.--. Pt. Mcintyre EOR Project Application - Testimony 1 . . and one gas injector, and that DS-PM2 will ultimately have 53-62 wells, including 1Q-13 water injectors. An additional water injector (P1-25) is located at the West Dock staging area. All Pt. Mcintyre water injection wells are completed with L-BO grade steel. All tubin 'ewel completed with 9-Cr/1 Moly, which is compatible with both L-BO and 13-Cr. PCMclnt re w i~n-èompletions are designed as single zone, single string with a single packer. Exhibits G- r::, I-~- 1 through G-5 show typical wellbore schematics for the five basic completion designs. The current waterflood pattern configuration for the Pt. Mcintyre Pool is an<!:nverted nine-s 0 This pattern selection provides maximum flexibility for potential future conversions 0 other pattern configurations as changes in reservoir description and/or performance dictate. Additional drilling within the EaR project area may be undertaken to improve sweep in areas of the reservoir unaffected by the hydrocarbon miscible EaR process and to result in the recovery of oil from areas and reservoir volume not otherwise affected by the implemented tertiary recovery activities. Future development plans will be based on field performance, including the performance of the 1 patterns already receiving M I. There are no plans to reduce well density below 40 acres. ) A surveillance program to monitor the Pt. Mcintyre EaR flood performance is in place and is based on experience of operating similar projects at the Prudhoe Bay and Kuparuk Fields. This program will be used to monitor field performance for field management and additional development opportunities. The Pt. Mcintyre EaR project involves the eventual conversion of the existing 15 waterflood injectors and potentially any future water injectors to water-alternating-gas CN AG) service. Water will be injected alternately with MI in the WAG injection wells to improve the MI sweep in the reservoir. At start up of the EaR project, water injection is anticipated to be approximately 250 MBWPD. Not all of the patterns will be receiving MI simultaneously. Those patterns not initially converted to WAG injection will remain on continuous water injection until MI is available. Source water is currently used for the Pt. Mcintyre waterflood. It is anticipated that the same injection water will be used during the initial stages of the EaR project. Conversion from source water injection to produced water injection is possible in later stages of the flood. Both of these water sources have been approved for injection into the Pt. Mcintyre reservoir under Area Injection Order No. 4B. ~ .~y. 111 ., fiV ~~M tvy ,(" , .j.J-J..,.... l ¡vJ'" ., c\ {'I-Á . ~ Currently, injection of an MI slug of 35 percent of hydrocarbon pore volume (HCPV) is planned. The maximum size of the MI slug for the project is limited by the rate of delivery of MI manufactured at the LPC. Exhibit S-1 shows the relationship between miscible injectant slu size andj¡1f'rement::¡1 oil recovery f0l.!... e Pt. Mcln yre ~nha~e I Recovery rOJec. ~ed at the LPC is expected to be delivered to Pt. Mcintyre at a nominal 50 MMSCFD. /Êxhibit S-2' hows the predicted incremental oil production rates for the Pt. Mcintyre Enhanced Oil ~o Project for the next 23 years for the miscible gas injection rate of 50 MMSCFD. Exhibit S shows the projected field oil production rates for the Pt. Mcintyre base (primary/secondary) d base plus EaR (50 MMSCFD) for this same period. Under the planned scope, the LPC MI supply will be limited, requiring the staging of MI injection into existing patterns as MI becomes available. Initially, two patterns will receive MI injection. As EaR patterns mature, the availability of excess MI will allow additional pattern(s) to begin receiving MI. Nominally, two patterns will be receiving MI at anyone time during the life of the project. It will take around 15+ years for the last pattern to receive its first MI slug. Peak incremental oil rate is expected to exceed 5 MBD as a resüïtollFi8P-rojëëT·-··--·--_··~- Current Pt. Mcintyre operations (processed gas re-injection and pattern waterflooding) are expected to yield an estimated total oil recovery of approximately 42 to 45% OOIP for the Pt. Mcintyre Pool. The planned hydrocarbon miscible EaR project at Pt. Mcintyre is estimated to Pt. Mcintyre EaR Project Application - Testimony 2 . . increase nil-leOOVery by an additional 32 MMSTB of oil, or approximately 6% of the OOIP within the current 15 pattern waterflood area. The existing waterflood patterns contain varied reservoir quality with incremental oil recovery estimates ranging from 4 to 8% OOIP of the targeted oil column under a hydrocarbon miscible EOR process. These estimates are based on analysis of core from 20 wells distributed around the field, detailed field wide stratigraphic correlations, PVT and fluid displacement laboratory studies, and fine scale fully compositional fluid flow reservoir simulations tied back to the laboratory data. The fine scale results were subsequently scaled up to a field wide scale, with the estimated incremental oil recovery for the waterflood area determined using the Pt. Mcintyre Full Field reservoir simulation model. MI for the Pt. Mcintyre EOR project will be manufactured at the LPC from a mixture of produced fluids from the Pt. Mcintyre, West Beach, North Prudhoe Bay, Niakuk, and Lisburne Pools. Based on the current operating practice of injecting processed natural gas from the LPC into the Pt. Mcintyre reservoir and given that the injected MI comprises the same hydrocarbon components in a more concentrated form, no compatibility problems are anticipated. The miscibility pressure criteria planned for the EOR project is designed to maximize oil recovery and miscible injectant utilization for an MI-limited project. The minimum enrichment level for the Pt. Mcintyre miscible injectant was determined from standard laboratory PVT and slim-tube displacement experiments. The blended MI will have a minimum miscibility pressure of approximately 4350 psi. The expected composition is given in Exhibit H-1. Injection and production at the Pt. Mcintyre field are managed to maintain the average reservoir pressure at the oriQinal pressure of approximately 4370 psi. There are no plans to change this reservoir management philosophy. Reservoir pressure monitoring is performed in accordance with Rule 12 of Conservation Order 317A and reported annually to the Alaska Oil and Gas Conservation Commission in the Pt. Mcintyre Oil Pool Annual Reservoir Report. The constant reservoir pressure with time along with negligible temperature variations across the field mean that miscibility pressure requirements are not expected to change as a result of reservoir conditions during the life of the EOR project. Similarly, the compact nature of the Pt. Mcintyre waterflood/EOR patterns exhibit negligible differences in reservoir conditions across the field. The minimum miscibility pressure/minimum miscibility enrichment evaluations for the project were performed at reservoir temperature (185°F). The thermal temperature bulb at Pt. Mcintyre, due to source water injection, should provide an MMP buffer, but the project design was 7 developed without including this factor. Taken together, these factors reduce the need for a large MMP buffer compared to other North Slope EOR projects. The projected potential maximum MI rate under the current scope is 70 MMSCFD. Expanding the Pt. Mcintyre Enhanced Oil Recovery Project by increasing the miscible gas injection rate beyond the current scope would require an external source of enriching components for manufacturing -\ ù" the additional miscible injectant. This is a technically viable option and was part of the initial ." \ scoping studies for an EOR Project at Pt. Mcintyre. However, when this initial evaluation J,L~" .\A indicated less favorable economics for this option, subsequent studies focused on self-generating .k-, . vC"'" I- MI project options. These studies resulted in the Owner decision to approve the funding of the' ï project described in the testimony today. Analyses to investigate the benefits of a miscible gas injection rate of up to 150 MMSCFD are being evaluated and will be based on the field performance under the current scope. Such a rate would require an external source of enriched MI, as well as additional drill site facilities and incremental capital expenditures. Pt. Mcintyre EaR Project Application - Testimony 3 . . Section B - Testimony of Murray P. Athans Mr. Chairman, members of the commission, ladies and gentlemen, my name is Murray P. Athans. I am the ARCO project engineer for the Pt Mcintyre EOR project. In this role, my job responsibilities have included facility design oversight and review, and acting as the primary coordinator between the engineering contractor and the Lisburne Production Center (LPG) Operations team. It has been my job to insure that the new facilities are fit for their intended purpose, are built to ARCO Alaska standards, and meet all operating and safety design requirements. I received a Bachelors of Science degree with Honors in Chemical Engineering from the University of Texas at Austin in 1978, and a Masters of Science degree in Chemical Engineering from the University of Texas at Austin in 1980. I began work for ARCO at the Exploration and Production Research Center in Piano, Texas in 1980, then transferred to ARCO Alaska in 1984. Since arriving in Alaska, I have worked in a broad variety of facility planning and process engineering positions within the Prudhoe Bay and Kuparuk business units. I transferred into the Greater Point Mcintyre Area in August, 1997, at which time I began my current assignment as Project Engineer for the Pt Mcintyre EOR project. I would like to be recognized as an expert witness. During my testimony today I will provide an overview of the facility modifications and additions which are being installed to implement the Pt Mcintyre EOR project. I will also briefly discuss some of the project facility considerations that impacted the MI rate projections previously discussed by John Hand. Vapors generated in the LPC NGL plant downstream from the feed flash drum, which are currently being injected as residue gas, will provide the enriching components for the MI solvent stream. Facility modifications are designed to ensure that the volume of blendable NGLs exJr...acted at the LPC will not be imRaçted by the EOR proje~t. Manufacture of MI at the LPC at a greater rate than planned for the project would adversely impact NGL production. The nominal annual average MI manufacture rate is expected to be 50 MMSCFD. During the summer months we expect to see an MI manufacture rate lower than winter months due to reduced NGL refrigeration capacity resulting from higher ambient temperatures. In the first 4-5 Jf\' fL"L-1 years of the project, MI rates during the summer are expected to range between 42-45 MMSCFD, while in winter ranging between 52-53 MMSCFD. After 4-5 years, MI rates should be consistently in the 50 MMSCFD range, with peaks as high as 60-70 MMSCFD. Peak rates estimates are based in part on predictions of the volumes of returned MI. The primary factors limiting the amount of MI manufacture at LPC are the LPC piping and vessel 7 metallurgical limit of -50°F (per ASME codes) and the plant refrigeration capacity. The new chiller installed as part of the project was sized to utilize the existing excess refrigeration capacity (propane system) at LPC. Increasing refrigeration capacity would require significant incremental capital. - Modifications at the LPC during 1999 and early 2000 in support of the Pt. Mcintyre EOR project "c&'¡ 24 include the installation of an MI compressor, a second chiller, new compressor coolers and c '~.- blending station, and an upgrade of the LPC NGL plant liquid piping. MI will be transported to the Pt. Mcintyre drill sites via a new distribution pipeline (shown in Exhibit A-1) using currently installed vertical support members. The EOR project will also require installation of drill site distribution piping. Pt. Mcintyre EOR Project Application - Testimony 4 . . H2S concentrations during the life of the project are expected to remain low. The equipment being installed is designed to handle the expected H2S concentrations. We will continue to observe existing H2S safety precautions. The estimated maximum and average injection pressures anticipated for the Pt. Mcintyre enhanced recovery projects are listed in the following table. These pressures represent pump discharge pressures. Injection Type Estimated Maximum Injection Pressure (psig) Estimated Average Injection Pressure (psig) Pt. Mcintyre Water Injection Pt. Mcintyre Mllnjection Pt. Mcintyre Gas Injection 2850 4500 5000 2250 4100 4300 The estimated maximum injection rates for Pt. Mcintyre enhanced recovery wells will not initiate1 ()JJ- tL,....... /1.. or propagate fractures through the confining strata, and, therefore, will not allow injection or lAS Þu>'$? formation fluid to enter any freshwater strata. All field data collected to date indicate that injection in the current water injectors and the single gas injector at Pt. Mcintyre has been confined to the injection strata. It is our expectation that the injected MI will remain confined to the injection strata. Existing water injection operations in the Pt. Mcintyre Pool Kuparuk River Formation have been above formation parting pressure to improve recovery of oil. In no instance have such injection pressures breached the integrity of the confining zone. Pt. Mcintyre EOR Project Application - Testimony 5 .. .. ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING January 13.2000 9:00 AM PtMcIntvrelWBeach NAME -AFFILIATION TELEPHONE Do yOU plan to testify? Yes No (pLEASE PRINT) M\C.\-I.AEL R. MC'R,&A"-.. '\ ;lh 3- Y ~~z.. YE? ~'~N:e~ ?NA a tt8" - ~ b a ò-- ,: 5 fo l/,.. 37òfo 0..,. e ,",1 . t.cb Drf"'l - X OM. (Y/ VI ~ (lfly IlTJ-I AN $" 2f4s--/3/ L Y£"5 \0)-/..1 L . tlhiVl) 2-6S,. 6o~b ýe.s. - --JtJ,..,.YG~TH 2' r= t. 9 L/ b Y£S, (Vt avk.. lA )ovr..~~ 2.~S'-~$"4~ vtG "" ~\(,. ~~~ ~. ~17~ '1Q '3'1-3 ¡V.:J 7t:f -3 -I z. 'Z- <I NO ... 23 ~c) 2- cóS· 1P:2.0 ~ ~~ .. .- Pt. Mcl ntyre Oil Pool Enhanced Oil Recovery Project West Beach Oil Pool Secondary Recovery Project Application for Injection and Amendment to Area Injection Order No. 4B West Beach Testimony January 12, 2000 January 12, 2000 .. .- Table of Contents SECTION A - TESTIMONY OF CARL E. LUNDGREN .......................................................................1 SECTION B - TESTIMONY OF MICHAEL R. MORGAN ...................................................................3 West Beach Secondary Recovery Project Application - Testimony .- .- Section B - Testimony of Michael R. Morgan Mr. Chairman, members of the commiSSion, ladies and gentlemen, my name is Michael R. Morgan. I am a Staff Petroleum Engineer with ARCO Alaska. I received a Bachelors of Science Degree in Petroleum Engineering from the Colorado School of Mines in 1986. I've been employed by ARCO since 1986 and have worked a variety of engineering projects. I have worked in the Greater Pt. Mcintyre Area on West Beach Pool development since February, 1996. I would like to be recognized as an expert witness. During my testimony today I will provide information regarding West Beach operations and the engineering aspects of the proposed West Beach Secondary Recovery Project. West Beach Pool startup occurred in April 1993. The field has been delineated by eleven penetrations consisting of seven wells and four sidetracks. Three wells currently are active, WB- 04, WB-05B and WB-06. Exhibit B-3 is a plat showing the location of West Beach area wells, including the three active wells. Our recent efforts have focused on delineation and further development of the West Beach reservoir, development of a secondary recovery plan, and construction of additional surface infrastructure to handle anticipated additional production from the West Beach reservoir. Secondary recovery plans at West Beach include water injection utilizing locally sourced water from Tertiary sands produced from a new well on the West Beach Pad. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 10 to 15% of the estimated 15-25 MMSTB original oil in place. Augmenting water injection with gas re-injection to capture attic oil along the southern fault trap is also being evaluated. Thus, our application requests authorization for both water and gas injection to enhance recovery from the West Beach Pool. The West Beach geologic model was updated in early 1998 to incorporate data from the West Beach 5 (WB-05) and West Beach 5A (WB-05A) penetrations. Utilizing this new geologic description and available data from area production and exploration wells, a detailed reservoir simulation model was constructed. The objectives of the model study were to screen potential development or delineation well locations and to evaluate secondary recovery options. Results from the study indicated a peripheral waterflood, injecting into WB-06 and producing from WB-04 and WB-05B, as the preferred development scenario, with estimated incremental recovery of 10- 15% of the original oil in place. The modeling study indicated that increased well density primarily tended to accelerate the base reserve profile, with little incremental recovery. However, waterflood performance data will be key to assessing additional development potential at West Beach. Currently the minimum well spacing is 80 acres, which should accommodate potential future drilling at West Beach. Recent drilling, production and surveillance data from WB-04, WB-05B and WB-06 have validated the modeling study and volumetrics. Post-fracture peak production from both WB-05B and WB-06 was initiated at 1700 STBOPD and 2487 STBOPD, respectively. Subsequently, production in WB-05B has fallen to 829 STBOPD, primarily due to reduced reservoir pressures in the area due to the increased offtake. The lower well rates and solution GOR of WB-05B make it difficult to keep the well on-line due to paraffin build-up associated with cold flowing temperatures. Production from WB-06 is currently at 800 STBOPD with associated gas of 11.2 MMSCFPD. Reservoir pressure monitoring indicates good connectivity between the wells as evidenced by the measured pressure drops of 500 to 750 psi following sustained production from all three wells. West Beach Secondary Recovery Project Application - Testimony 3 .. .- These pressure drops are· consistent with the reservoir model and confirm lateral connectivity between wells. Lack of connectivity is a key risk to secondary recovery. The West Beach waterflood involves conversion of WB-06 to injection service in the first quarter of 2000. The conversion will be conducted in accordance with 20 AAC 25.412. The WB-07 source water well (permit no. 199-106) will supply injection water with an electrical submersible pump producing water from the Tertiary sands at a maximum rate of 10,000 BWPD and 2100 psi surface pressure. This source water well is currently being drilled. Exhibit E-1 shows the planned and potential completion intervals on the WB-01 shallow section log. A local water sample from the target water source interval has not been obtained. However, it is anticipated the water will be of similar composition to that produced from the GC-3 water wells as shown in Exhibit M-1 from the April 5, 1993 "Application for Modification to Area Injection Order no. 4." Electric log salinity calculations from the West Beach State #1 well indicate salinities of 20,000 to 40,000 ppm, which are consistent with the GC-3 water sample analyses and previous log calculations. Laboratory testing, core analyses and geochemical modeling indicate no significant problems with clay swelling or in-situ fluid compatibility. Analysis of a sample of the West Beach 4 core in a lower quality interval indicates significant amounts of clay (11 %) may be present, primarily in the form of Kaolinite. The presence of this clay may cause pore plugging in conventional unstimulated producing wells at waterflood breakthrough. However, both West Beach producing wells are hydraulically fracture treated, which will minimize fluid velocities and subsequent fines movement in the rock near the producing wells and thus minimize the potential for producing well formation damage. Calculations for WB-04 show the velocities are 280 times less for the fractured completion compared to an unstimulated completion. No evidence of fines migration was observed during the initial post-frac clean-up t43StS in any of the wells. The Tertiary water is expected to contain excess barium at concentrations from 50 ppm to in excess of 300 ppm. If uninhibited, barium sulfate scale could result when West Beach produced water is mixed with Pt. Mcintyre produced water containing excess sulfate (S04) associated with seawater breakthrough. However, the West Beach produced water stream will be inhibited upstream of the Pt. Mclntyre/West Beach commingling point to prevent BaS04 precipitation. Because West Beach has not produced any formation water, reservoir compatibility modeling and laboratory testing assumed a water composition similar to that of the Pt. Mcintyre pool. Initially, the waterflood will be managed to replace reservoir voidage. As the flood progresses, injection rates will be adjusted in response to producing well surveillance and performance. New facilities installed and in service on the West Beach pad include a central manifold designed to collect production from four initial wells and five additional wells. The pad will also have a new chemical injection skid and a new electrical distribution skid. A new 12" pipeline has been installed from the West Beach pad to drill Sit43 L 1 to handle increased production rates. Additionally, a 4" high pressure line has been installed that will be used to supply lift gas to the pad. The line has been designed to accommodate high pressure gas or miscible injectant if additional pressure maintenance or tertiary recovE~ry can be justified. The existing 6" production line will be converted to a dedicated test line. To facilitate initiating production from the WB-OSB and WB-06 wells, design and material procurement for the facility expansion occurred prior to drilling the wells. Consequently, sizing considered the low incremental cost for additional slots and various future development scenarios, including potential additional drilling for West Beach or other GPMA fields. Waterflood performance data will be key to assessing additional development potential at West Beach. West Beach Secondary Recovery Project Application - Testimony 4 .. .- Exhibit B-3 ~ tQ. . ~~, ....:¡ + .8..:..:.·"...;,· ¡ , I -~·l· I. If.) ~ + + 1 ~ ... '. 1·\'·' .. .tQ, ',.. ·'ii,'Y'~ ;.. ...--"" ~. .~... /" ... ~ /'. . ~ ./ . 0') I C\~ ¡ ~....J, ....:¡ \ \ ~. I è:; , ...:¡ ~.. .... :,. ,~, " ~ a co ::..:~~... C\J :...: ~ ~I -~ \ ..... ~ ~ 0) "t.~\ \ \ .'\ '+ ~ ....:¡ ~ r.JJ Q) Cr) 1:\/ ~ (....~-.' ¡:>- r~>t- ~O') ;'I: -' t)*' CQ Ie ~, 0 .~ ~ "'-~."l P J<y I tB .............. + p:¡ - ~,/ Exhibit B-3 i \ 117 I II I() 'I ..:¡ 0) l í ¡-(-u + IQ....~ ..... . '\Q." '4 \. , ì ¡ -it- ì. <~ . I ! 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ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING Ii POINT McINTYRE OIL POOL ENHANCED OIL 5 II RECOVERY PROJECT and WEST BEACH OIL POOL II SECONDARY RECOVERY PROJECT APPLICATION 6 II FOR INJECTION AND AMENDMENT TO AREA INJECTION ORDER NO. 4B. 7 8 TRANSCRIPT OF PROCEEDINGS 9 10 Anchorage, Alaska January 12, 2000 9:03 o'clock a.m. 11 APPEARANCES: 12 Commissioners: MS. CAMILLE OECHSLI MR. DAVE JOHNSTON 13 14 * * * * * * 15 16 17 18 19 20 21 22 23 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 .. .. 2 1 PRO C E E DIN G S 2 (On record 9:03 a.m.) 3 COMMISSIONER OECHSLI: Good morning. It's 4 about three minutes after 9:00 on January 12th. We're at the 5 Commission Office at 3001 Porcupine Drive. This hearing was 6 originally set for ARCO's application for injection and 7 amendment to area injection order number 4B with respect to the 8 Point McIntyre Oil Pool Enhanced Oil Recovery Project, and the 9 West Beach Oil Pool Secondary Recovery Project. The notice was 10 published on November 20, 1999, in the Anchorage Daily News for 11 this hearing. 12 Present at the head table: Dave Johnston, Cammy 13 Oechsli. Present in the room are John Groth, Mark Worcester 14 from ARCO, and Kristen Nelson from Petroleum News. 15 Are we prepared to proceed? 16 COMMISSIONER JOHNSTON: You've got to put on 17 record what the purpose of the hearing is. 18 COMMISSIONER OECHSLI: Purpose of the hearing 19 was for the ARCO's application. 20 COMMISSIONER JOHNSTON: Okay. Before we 21 proceed further, I would like to recuse myself from further 22 deliberations in these matters. And the reason for that lS 23 that I have been advised by the Governor that I would not be 24 reappointed to the Commission so I am now serving my last few 25 days with this organization. Because of that, I think it would MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 .. .. 3 1 be inappropriate to be sitting in a decision-making matter 2 concerning an affair of a company who I will probably be 3 approaching for future employment opportunities. For that 4 reason, I think there would be an ethical violation if I was to 5 sit in judgment of a decision that is now pending before us. 6 And for that reason, I feel it appropriate that I recuse myself 7 from further deliberations in this matter. 8 COMMISSIONER OECHSLI: On Mr. Johnston's 9 request, we no longer have a quorum since Mr. Christenson is 10 not here. I apologize, Mr. Groth, and Mr. Worcester, for the 11 inconvenience. If you have no objection, we could recess the 12 hearing now and continue it to tomorrow morning at 9:00 13 o'clock. 14 MR. GROTH: Well, we have no objection. 15 COMMISSIONER OECHSLI: Is there anything 16 further you would like to take up before we go off record? 17 MR. GROTH: No, there's not. 18 COMMISSIONER OECHSLI: Okay. With that, we'll 19 go ahead and recess then until tomorrow morning at 9:00 20 o'clock. 21 (Off record 9:07 a.m.) 22 END OF PROCEEDINGS 23 24 25 METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 A.IIe/wrage, Alaska 99501 (907) 276-3876 .. .. 4 1 C E R T I FIe ATE 2 UNITED STATES OF AMERICA) )ss. snrn OFA~S~ ) 3 4 I, Laura Ferro, Notary Public in and for the State of 5 Alaska, and Reporter for Metro Court Reporting, do hereby 6 certify: 7 That the foregoing Alaska Oil & Gas Conservation 8 Commission Public Hearing, was taken before me on the 12th day 9 of January 2000, commencing at the hour of 9:03 o'clock a.m., 10 at the offices of Alaska Oil & Gas Conservation Commission, 11 3001 Porcupine Street, Anchorage, Alaska; 12 That the hearing was transcribed by me to the best of 13 my knowledge and ability. 14 IN WITNESS WHEREOF, I have hereto set my hand and 15 affixed my seal this 9th day of March 2000. 16 ~~ Notary Public ln and for Alaska My commission expires: 05/03/01 17 18 19 20 21 22 23 24 25 MET ROC 0 U R T R E P 0 R TIN G, INC. 550 West Sevellth Avellue, Suite 1650 Allchorage, Alaska 99501 (907) 276-3876 .. .- ALASKA OIL AND GAS CONSERV A nON COMMISSION PUBLIC HEARING January 12.2000 9:00 AM PtMclntvre/WBeach NAME - AFFILIA nON TELEPHONE Do vou Dlan to testifv? Yes No (pLEASE PRINT) ::¡ 0 1+:1 GRO ï1~ ~W~ ; ~º-'vl rvelS.ð N- A 2.t..s- -t:. S 1 (., ~~~ftr~ '4.{ v-w We / #4 .. .. BP EXPLORATION ENGINEERING DATA SUBJECT ~.~ J þ~ ~ (,. ~D\l BASED ON ENGINEER SHEET NO._OF_ DEPT. APP'VL BUDGETIAFE NO. DATE ~CJ.." \0 ~ILE NO. ~ """-. "'~~"~<:L'- vv\ l kE MðR6AN ~ -o~" L . /;fA'" C fYJU(2¡(f}'-( /lTI-I-ANS C-Af&.L- LUÑD~&...1 -.J ()~/C.Æ<;-;¡::¡- ~~~4/ ~ Mdv,(. ~1X-~ V/~.s AK 2337-' (3/94) ~a~ '--'- \ ~ Š - \;) S-<:...J ARCð ;Z~ 3 -'-{332.. A fl. co 2. I:, S- - bo.!" ¡:rte cc ¿~ 5"""-1 31"2- Afi!,.a 0 2. Cø ':, . G,2.o~ ¡9-Æ c¿) Z¿'S- &, ~ Jj ~ /fbéCc 7/j>--/¿.~ Ao~(,c '74'07 éC 7-0 3, - / 2. ~ f -;R3-IZZ'l *3 ,. . .-.-.. , - -- ... , - - TONY KNOWLES. GOVERNOR ALASKA. OIL Alft) GAS CONSERVATION COltDlISSION 3001PORCUPINE DRIVE ANCHORAGE. ALASKA 99501·3192 PHONE: (907) 279-1433 FAX: :907) 276-7542 December 1. 1999 Mr. J. W. Groth ARCO Alaska. Inc. PO Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Groth: The Commission will hold a hearing on January 12,2000 concerning your November 8. 1999 application for authority to initiate a watertlood in the West Beach Oil Pool and a miscible gas project in the Point McIntyre Oil Pool. The purpose of this hearing is to insure the public record is as complete and accurate as possible for this important matter. The Commission staff has reviewed your application and requests that information be provided to the Commission to address the following questions. Point McIntyre I) Existing well spacing in the Point McIntyre Oil Pool is 40 acres per well: will the increased well density your project envisions require a closer spacing? 2) What is the relationship behvecn miscible slug size and oil recovery (miscible injectant volume Vs incremental oil recovery)" 3) The proposed minimum miscibility pressure for the injectant is 20 psi belo\',' the average reservoir pressure: this difference is much less than in other North Slope miscible gas projects. What actions will Arco take to insure miscibility is maintained field wide? \\That are the impacts of manufacturing iUJectant with a minimum miscibility pressure 100 psi below average reservoir pressure" Is the proposed solvent likely to increase ultimate recovery over a richer solvent with a lower miscibility pressure'! If so why'! 4) \\t'hat arc the projected production rates for the next 23 years for miscible gas injection rates of 50 mmcfì'd and 150 mmcf/d') (Show primary recovery. watertlood recovery and miscible gas incremental oil volumes separately). 5) Can sufficient enriching components to manufacture 150 mmcf/d of miscible injectant be obtained at the Lisburne Production Facility without impacting ngl production" 6) What are the sensitivities for manufacturing 150 mmcf/d of miscible injectant') 7) Is miscible injectant from an external source a viable option? Ifnot why? 8) What are the proJections for H2S concentrations and associated problems. if any" WEST BEACH I) TIle phi*h and structure map (annotated with fluid contacts) used in generating the current volumetrics should be included in the exhibits. ~ .. .. 1. W. Groth 2 December I, 1999 2) Are the net sand trends corroborated with seismic data. or are they based on a geologic model and well control? 3) West Beach facilities envision additional wells. do these include delineation wells? 4) Is the 10-15% incremental waterflood recovery estimate based on existing wells? Will additional wells increase incremental recovery? To ""'hat extent? 5) Current well spacing is 160 acres, is a closer spacing warranted? 6) Significant amounts of clay are present in the West Beach #4 core. which raises concerns about pore plugging and fines migration. Please discuss potential problems and mitigation techniques. Please describe your plans to obtain and analyze additional rock samples during drilling of future wells. We look forward to receiving your reply to this information request. In order to allow the Commission staff adequate time to review your submittal prior to the hearing, your reply is requested as soon as possible. Please contact Jack Hartz or Bob Crandall of this office if you wish to discuss any of the items listed above. Robert N. Christenson. P. E. Chair .:\f2 . . Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Pt McIntyre and West Beach Oil Pools in the Prudhoe Bay Unit ARCO Alaska, Inc. by letter dated November 8, 1999, has requested authority to initiate a Miscible Gas Injection Tertiary Oil Recovery Project at Pt McIntyre and a Water Injection Enhanced Oil Recovery Project at West Beach. A person who may be harmed if the requested order is issued may file a written protest prior to 4:00 PM, December 6, 1999 with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501. and request a hearing on this matter. If the protest is timely filed a hearing on the matter will be held at the above address at 9:00 AM on January 12, 2000, in conformance with 20 AAC 25.540. If no protest is filed, the Commission will consider the issuance of the order without a hearing. If you are a person with a disability who may need a special modification in order to comment or to attend the public hearing, please contact Diana Fleck at 793-1221 before January 5, 2000. ¿;~ Robert N. Christenson, P.E. Chairman Published November 20 1999 ADN AO# 02014016 · Affidavit of Publicat. Ad # Run Dates ED Po # Price per Account day 217069 11/20/99 ON 02014016 $67.50 STOF0330 STOF0330 $67.50 STATE OF ALASKA THIRD JUDICIAL DISTRICT Eva Alexie, being first duly sworn on oath deposes and says that she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on the above dates and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. C C "- Legal Clerk_~~~_~~~_ ---~--~~~---------- A person who may· bet IIormed .. if tlM!requested otder is issued. may ffle 0 written' protest prior to 4:00 PM, .December 6. 19W'with the Alaska·· Oil . and Gas CGnservatioil ~ommission, 3001 Porcu"pine Driv.e, Anchorage. Alaska 99501, and ~uest a hearing on this matter. I f the protest is timely filed a hearing on the matter will bet held at the above address at 9:00 AM on January 12. 20000' in conformance with 20 AAC· 25.S40. If no protest is filed, the Commission will con-. sider the issuance of the· order withollt 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 betfore January 5. 2000. IsIRobert N. Christenson P.E.. Chairman Pub.: 11120199 Subscribed and sworn to me before this date: __()~-'¿(H6.l/:_~I-Lj_?1 Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: ø &: :;2 IIJ(J v \\í(rrl!{((/~ .\.\\:-{ ',3Ul¿o'l,> S..~~ .' . :.: '. C'.Lr/ ........... -" -.... ~ ~r r- :,:::~..' O)ARk: :-:-. -.::: .. ~_..- ..- :::PUB~f : - % '. \P~>.. ::-~\,~.~. f ../ . 'O'l: vr ,...... --:~.' ~ --<\ <I) , ' ,"\ '- ·;)!I!ì)j1)Î\· ~1 , ARCO Alaska, Inc. . Post Office Box: I 00360 Anchorage, Alaska 99510-0360 Telephone 907 2761215 . ~~ ~". Greater Pt. Mcintyre Area November 8, 1999 Robert N. Christensen, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 ORIGINAL RE: Pt. Mcintyre Field Enhanced Oil Recovery Project and West Beach Secondary Recovery Project Application for Injection and Amendment to Area Injection Order No. 4B. Dear Mr. Christensen: Enclosed is the Pt. Mcintyre Field Enhanced Oil Recovery Project and West Beach Secondary Recovery Project Application for Injection and Amendment to Area Injection Order No. 4B. The application was prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). ARCO Alaska, Inc. as Operator of the Pt. Mcintyre and West Beach Pools, seeks Alaska Oil and Gas Conservation Commission endorsement and authorization for the proposed projects and amendments to Area Injection Order 4B. In the event that a public hearing is held under 20 AAC 25.540, we would like to meet with the Commission prior to the hearing, if held, for clarification of the hearing procedures and deadlines. ARCO Alaska, Inc. will be prepared to provide testimony in support of the application, and we anticipate that it will take about one day to present our testimony. Please contact J. W. Groth (265-6846), M. R. Morgan (263-4332) or J. L. Hand (265- 6036) if you have questions or require additional information. Sincerely, ~----- .-../, }¡) L 7,{".j ; ;-t J. W. Groth Attachments cc: D. W. Bose (AAI) ARea Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany . . M. P. Evans (Exxon) J. Hurliman (SPA) . . Pt. Mcintyre Oil Pool Enhanced Oil Recovery Project West Beach Oil Pool Secondary Recovery Project Application for Injection and Amendment to Area Injection Order No. 48 20 AAC 25.402 20 AAC 25.460 November 8, 1999 November 8, 1999 . . Table of Contents Section A - Application for Injection and Amendment to Area Injection Order No. 48 ....................1 Section 8 - Plat of Project Area...................................................... ........................................... ....... 3 Section C - Operators/Surface Owners............................................................................................ 4 Section D - Affidavit........................................................................................................... ......... ......6 Section E - Description of Operation........................................ ........... .......... ................. ...... ....... ..... 7 Section F - Geologic Information.... ....... .......................................................................................... 9 Section G - Injection Well Casing Information................................................................................10 Section H - Injection Fluids.. .......................... ............................. .... ............. ........... .... .............. ......11 Section I - Injection Pressures.......... .............................................................................................. 13 Section J - Fracture Information......................... ........................ .......................... .......................... 14 Section K - Hydrocarbon Recovery ................................................................................................15 Section L - Proposed Findings .......................................................................................................16 Section M - Recommended Conclusions ......................................................................................19 Section N _ Requested Decisions................................................................................................. .20 Exhibits.......................................................................................................................................... . 21 Pt. Mcintyre EOR Project Application . . List of Exhibits Exhibit A-1: Greater Pt. Mcintyre Area Drillsites and Pipeline Routing Map Exhibit B-1: Plat of Wells Within Pt. Mcintyre Participating Area Exhibit B-2: Pt. Mcintyre Injection Wells Exhibit B-3: Plat of West Beach Pool/Participating Area Exhibit C-1: Native Allotment Parcel Map Exhibit 0-1: Affidavit Exhibit E-1: West Beach Shallow Section Type Log WB-1 - Source Water Targets Exhibit F-1: West Beach West to East Structural/Stratigraphic Cross-Section Exhibit F-2: West Beach Reservoir Net-to-Gross Map, Post West Beach 6 Exhibit G-1: Pt. Mcintyre Well Schematic - Conventional Gas Injection Well Design Exhibit G-2: Pt. Mcintyre Well Schematic - Conventional Water Injection Well Design Exhibit G-3: Pt. Mcintyre Well Schematic - Slimhole Water Injection Well Design Exhibit G-4: Pt. Mcintyre Well Schematic - Ultra Slimhole Water Injection Well Design Exhibit G-5: Pt. Mcintyre Well Schematic - Mono-bore Water Injection Well Design Exhibit G-6: West Beach Well Schematic - WB-04 Exhibit G-7: West Beach Well Schematic - WB-06 Exhibit H-1: Pt. Mcintyre Miscible Injectant Compositional Analysis Exhibit H-2: LPC Reinjection Gas Compositional Analysis Pt. Mcintyre EOR Project Application . . Section A - Application for Injection and Amendment to Area Injection Order No. 48 20 AAC 25.460 20 AAC 25.402 ARCO Alaska, Inc. ("ARCO"), in its capacity as a Working Interest Owner (WIO) in, and Operator of, the Pt. Mcintyre and West Beach Oil Pools, hereby applies for Alaska Oil and Gas Conservation Commission (Commission) authorization to inject an enriched hydrocarbon miscible gas in the Pt. Mcintyre Pool and water and gas in the West Beach Pool for the Pt. Mcintyre Pool Enhanced Oil Recovery (EaR) Project and the West Beach Pool Secondary Recovery Project, respectively, for the purpose of enhanced recovery of oil, and amendment to Area Injection Order No. 4B, issued April 13, 1998. This application has been prepared in accordance with 20 AAC 25.402 (Enhanced Recovery Operations) and 20 AAC 25.460 (Area Injection Orders). It follows the same format and exhibit numbering as set forth in the Application for Modification to Area Injection Order No.4, dated April 5, 1993. Pt. Mcintyre Pt. Mcintyre Pool startup occurred in October 1993. Current operations involve a combination of processed gas reinjection and 80-acre inverted nine-spot pattern waterflooding for pressure maintenance. Gas reinjection into the gas cap began concurrent with field startup, while waterflood injection began in July of 1994. As of January 1, 1999, fifteen water injectors and one gas injector provide pressure support to the reservoir, maintaining average reservoir pressure at the original pressure of approximately 4370 psi. Source water, from the Seawater Treatment Plant, is currently used for the Pt. Mcintyre waterflood. Pt. Mcintyre production is processed at the Lisburne Production Center (LPC). Field oil production reached a facility-constrained plateau of 165,000 BOPD during the second quarter of 1996 and this nominal rate was maintained until the third quarter of 1997. Oil production has since declined due to increasing water cuts at Pt. Mcintyre and water handling constraints at the LPC. To enhance recovery of oil at pt. Mcintyre, the Working Interest Owners (ARCO, BPA and Exxon) have approved a hydrocarbon miscible EaR project. Vapors generated in the LPC NGL plant downstream from the feed flash drum, which are currently being injected as residue gas, will provide the enriching components for the miscible injectant (MI) solvent stream. Facility modifications are designed to ensure that the volume of blendable NGLs extracted at the LPC will not be impacted by the EaR project. Planned startup for MI injection is the first quarter of 2000. Additional Pt. Mcintyre EaR project details are provided in the discussion of the specific requirements of 20 AAC 25.402(c). Proposed findings, recommended conclusions, and requested decisions of the Commission are included at the end of this application. West Beach West Beach Pool startup occurred in April 1993. The field has been delineated by eleven penetrations consisting of seven wells and four sidetracks. Three wells currently are active, WB- 04, WB-05B and WB-06. Recent work efforts have focused on delineation and further development of the West Beach reservoir, development of a secondary recovery plan, and construction of additional surface infrastructure to handle additional production from the West Beach reservoir. Significant progress has been made in developing the West Beach reservoir, including plans for secondary recovery. Pt. Mcintyre EaR Project Application 1 . . Secondary recovery plans at West Beach include water injection utilizing locally sourced water from Tertiary sands produced via a new well on the West Beach Pad. Reservoir simulation studies indicate incremental recovery from waterflooding to be between 10 to 15% of the estimated 15-25 MMSTB original oil in place. Additionally, augmenting water injection with gas re- injection to capture attic oil along the southern fault trap is being evaluated. This application requests authorization for both water and gas injection to enhance recovery from the West Beach Oil Pool. Additional West Beach Secondary Recovery Project details are provided in the discussion of the specific requirements of 20 AAC 25.402(c) or by reference to the Application for Modification to Area Injection Order No.4, dated April 5, 1993. Proposed findings, recommended conclusions, and requested decisions of the Commission are included at the end of this application Pt. Mcintyre EaR Project Application 2 . . Section B - Plat of Project Area 20 AAC 25.402(c)(1) Exhibit B-1 and B-3 are plats showing the location of all existing injection wells, production wells, abandoned wells, dry holes, and any other wells within the Pt. Mcintyre Pool or West Beach Pool, respectively, as of June 1, 1999. The current Pt. Mcintyre water and potential miscible solvent injector locations are identified in the plat shown in Exhibit B-1 and are tabulated in Exhibit B-2. Specific approvals for any new injection wells or existing wells to be converted to injection service will be obtained pursuant to 20 AAC 25.005, 25.280 and 25.507, or any applicable successor regulation. Pt. Mcintyre EOR Project Application 3 . . Section C - Operators/Surface Owners 20 AAC 25.402(c)(2) The Pt. Mcintyre and West Beach PAs are operated by ARCO Alaska, Inc. The Surface Owners within one-quarter mile and inclusive of the Pt. Mcintyre and West Beach PAs are listed in the following table. The Native Allotment Landowners are listed by allotment parcel. Exhibit C-1 is an areal map of the parcels. Surface Owners State of Alaska Department of Natural Resources Attn: M. Kotowski P.O. Box 107034 Anchorage, AK 99510 Parcel 17 CUSS 6905) Alice Glenn 899 Blair Ave. Sunnydale, CA 94087 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Selection within Section 28 CADL 414852) George Ahmaogak P.O. Box 338 Barrow, AK 99723 City of Barrow City of Barrow P. O. Box 629 Barrow, AK 99723 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Parcel 16 CUSS 9137) Lawrence Ahmaogak P.O. Box 411 Barrow, AK 99723 Lawrence Ahmaogak P.O. Box411 Barrow, AK 99723 And And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Pt. Mcintyre EOR Project Application 4 . Parcel 16 CUSS 9267) John P. Nicholls (minor) C/o Ely Varner (guardian) P.O. Box 473 Barrow, AK 99723 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 USS 4044 United States Department of the Navy U.S. Dept. of Navy Commanding Officer (Code 05LM) Engineering Field Activity NW Naval Facilities Engineering Command 19917 7th Ave., NE Poulsbo, WA 98370-7570 Pt. Mcintyre EOR Project Application . Parcel 18 CUSS 6906) Barbara Ahmaogak, Life Estate Holder 1628 Hilton Ave. Fairbanks, AK 99701 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Lawrence Ahmaogak, George Ahmaogak and Alice Glenn, remaindermen (service as provided above) Parcel NA F-14632 Wallace Oenga, Georgene Shugluk, Leroy Oenga, Michael Delia and Jennie Oenga (deceased, probate pending) C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-44 5 . . Section D - Affidavit 20 AAC 25.402(c)(3) Exhibit D-1 is an affidavit showing that the Operators and Surface Owners within a one-quarter mile radius of the area included in the Pt. Mcintyre and West Beach PAs have been provided a copy of this application for injection and amendment to Area Injection Order No. 48. Pt. Mcintyre EOR Project Application 6 . . Section E - Description of Operation 20 AAC 25.402(c)(4) Pt. Mcintyre Enhanced recovery injection wells are used for the introduction of additional fluids into the reservoir to increase the ultimate recovery of oil. Currently, two types of injection wells are in operation at Pt. Mcintyre: produced gas reinjection and water injection. Gas reinjection began concurrent with field startup, with water injection beginning in July of 1994. As of January 1, 1999, fifteen water injectors and one gas injector provide pressure support to the reservoir, maintaining average reservoir pressure at the original pressure of approximately 4370 psi. Source water, from the Seawater Treatment Plant, is currently used for the Pt. Mcintyre waterflood. Seventy-four wells have been drilled in the Pt. Mcintyre pool through January 1, 1999 (not including P&A'ed wells). The two Pt. Mcintyre drill sites, PM1 and PM2, have production, water injection, and gas lift facilities in place. Drill site PM1 also has gas injection facilities in place. Ultimate well count at Pt. Mcintyre is envisioned to be as high as 86 wells (not including P&A'ed wells), depending on the number of 80-acre infill wells and the extent of peripheral development. Present estimates are that DS-PM1 will ultimately have 20-23 wells, including four water injectors and one gas injector, and that DS-PM2 will ultimately have 53-62 wells, including 10-13 water injectors. An additional water injector (P1-25) is located at the West Dock staging area. The current waterflood pattern configuration for the Pt. Mcintyre Pool is an inverted nine-spot. This pattern selection provides maximum flexibility for potential future conversions to other pattern configurations as changes in reservoir description and/or performance dictate. Additional drilling within the EOR project area may be undertaken to improve sweep in areas of the reservoir unaffected by the hydrocarbon miscible EOR process and to result in the recovery of oil from areas and reservoir volume not otherwise affected by the implemented tertiary recovery activities. The Pt. Mcintyre EOR project involves the eventual conversion of the existing 15 waterflood injectors and potentially any future water injectors to water-alternating-gas (WAG) service. Currently, injection of an MI slug of 35 percent of hydrocarbon pore volume (HCPV) is planned. MI generated at the LPG is expected to be delivered to Pt. Mcintyre at a nominal 50 MMSGFD. At this rate, MI injection would occur for a period of approximately 23 years to inject the entire 35 percent HGPV slug in the existing patterns. Peak incremental oil rate is expected to exceed 5 MBD as a result of the project. Potential benefits from additional MI for the EOR project are being evaluated. Increased MI volume would provide flexibility with respect to project phasing and WAG ratios. Vapors generated in the LPG NGL plant downstream from the feed flash drum, which are currently being injected as residue gas, will provide the enriching components for the MI solvent stream. Facility modifications are designed to ensure that the volume of blendable NGLs extracted at the LPG will not be impacted by the EOR project. Planned startup for MI injection is the first quarter of 2000. Modifications at the LPG during 1999 in support of the Pt. Mcintyre EOR project include the installation of an MI compressor, a new parallel chiller, new compressor coolers and blending station, and an upgrade of the LPC NGL plant liquid piping. MI will be transported to the Pt. Mcintyre drill sites via a new distribution pipeline (shown in Exhibit A-1) using currently installed vertical support members. The EOR project will also require installation of drill site distribution piping. Pt. Mcintyre EOR Project Application 7 . . West Beach The West Beach geologic model was updated in early 1998 to incorporate data from the West Beach 5 (WB5) and West Beach 5A (WB5A) penetrations (Exhibit B-3). Utilizing this new geologic description and available data from area production and exploration wells, a detailed reservoir simulation model was constructed. The objectives of the model study were to screen development/delineation well locations and to evaluate secondary recovery options. Results indicated peripheral waterflood as the preferred development scenario, with estimated incremental waterflood recovery factors from 10-15% of the original oil in place. Pending successful testing and sustained production from both WB-05B and WB-06, a peripheral waterflood is planned for the reservoir The West Beach waterflood involves conversion of one well, either WB-06 or WB-04, to injection service in the first quarter of 2000. The decision of which well to convert will be dictated by additional performance data from all wells in the field. Planning , design engineering and funding have been completed for drilling a source water well on the West Beach pad and converting WB-06 to water injection service. The source water well would supply injection water via an electrical submersible pump sourcing water from the Tertiary sands (Exhibit E-1). Initially, the waterflood would be managed to replace reservoir voidage. As the flood progresses, injection rates would be adjusted in response to producing well surveillance and performance. Augmenting water injection with gas re-injection to capture attic oil along the southern fault trap is being evaluated. Thus, this application requests authorization for both water and gas injection to enhance recovery from the West Beach Oil Pool. The source water well will be permitted and constructed in accordance with 20 AAC 25.005. New pad facilities installed and in service on the West Beach pad include a central manifold designed to collect production from four initial wells and five future wells. The pad will also have a new chemical injection skid and a new electrical distribution skid. A new 12" pipeline has been installed from the West Beach pad to drill site L 1 to handle increased production rates. Additionally, a 4" high pressure (5230 psi) line has been installed that initially will be used to supply lift gas to the pad. The line has been designed to accommodate high pressure gas or miscible injectant should additional pressure maintenance or tertiary recovery be justified. The existing 6" production line will be converted to a dedicated test line. The pipelines and manifold skid have been installed and are in service on the pad. Pt. Mcintyre EaR Project Application 8 . . Section F - Geologic Information 20 AAC 25.402(c)(6) Pt. Mcintyre Refer to Section G of the "Application for Modification to Area Injection Order No.4", dated April 5, 1993. West Beach The West Beach Pool produces from the Lower Cretaceous (Late Hauterivian) Kuparuk River Formation. The Kuparuk River formation in this area is a package of sand to conglomerate sized debris flows that have infilled the West Beach graben, prograding from south to north and west to east. Reservoir quality decreases away from the bounding fault in a distal direction toward the basin (refer to Exhibits F-1 and F-2). Biostratigraphic data indicate the productive sands in the West Beach reservoir are younger than the reservoir quality sands in the lower Kuparuk River formation section of the Gull Island 3 well to the east. The interval targeted for enhanced recovery at West Beach is defined by Conservation Order 311A Rule 2, which defines the pool as the accumulation which is common to and correlates with the accumulation found in the West Beach No.4 well between the depths of 14,458' MD and 14,781' MD (refer to Exhibit G-11 in the "Application for Modification to Area Injection Order No. 4, dated April 5, 1993"). Refer to Section G of the "Application for Modification to Area Injection Order No.4", dated April 5, 1993, for additional information. Pt. Mcintyre EOR Project Application 9 . . Section G - Injection Well Casing Information 20 AAC 25.402(c)(8) Pt. Mcintyre Currently, 15 water injectors and one gas injector are in service in the Pt. Mcintyre Pool. A wide range of departures have been drilled in Pt. Mcintyre with a maximum injection well departure of over 13,300 feet (P2-47). Injection well tubing sizes in the Pt. Mcintyre pool vary from 2-7/8" to 7" with the majority being 4- 1/2" and 5-1/2". In general, the production casing is sized to the tubing in the Pt. Mcintyre wells. Development wells utilize either a "conventional," "slimhole," "ultra slimhole," or "mono-bore" design similar to designs used in the Kuparuk River Unit and other Prudhoe Bay Unit wells. The "conventional" design wells requiring 5-1/2" tubing utilize 13-3/8" surface casing, 9-5/8" production, or intermediate casing with a 7" liner for the high step out wells. The "slim hole" design wells requiring 4-1/2" tubing utilize 10-3/4" surface casing, 7-5/8" production, or intermediate casing with a 4-1/2" liner for high step out wells. The lower rate wells utilize the "ultra slimhole" design, a 4-1/2" tubing string inside a 7" production string with 9-5/8" surface pipe. One well (P2-34) is a "mono-bore" completion with 9-5/8" production casing and a 5-1/2" liner over the production interval with 5-1/2" tubing. All Pt. Mcintyre water injection wells are completed with L-80 grade steel. All tubing jewelry is completed with 9-Cr/1 Moly, which is compatible with both L-80 and 13-Cr. Pt. Mcintyre water injection completions are designed as single zone, single string with a single packer. Exhibits G-1 through G-5 show typical wellbore schematics for the five basic completion designs. West Beach WB-06 or WB-04 will be converted to injection service for the West Beach waterflood. The casing program for both WB-04 and WB-06 were permitted and completed in accordance with 20 AAC 25.030. Cement bond logs were recorded in both wellbores prior to running the completion. The bond logs and fracture treatment data indicate isolation of the target injection zone. Well conversion will be conducted in accordance with 20 AAC 25.412. Exhibits G-6 and G-7 detail the completions for WB-04 and WB-06, respectively. The actual casing program is included with the "Application to Drill" for each well and is documented with the AOGCC in the completion record. API injection casing specifications are included on each drilling permit application. All injection casing is cemented and tested in accordance with 20 AAC 25.412 for both newly drilled and converted injection wells. All drilling and production operations will follow approved operating practices regarding the presence of H2S in accordance with 20 AAC 25.065. pt. Mcintyre EOR Project Application 10 . . Section H - Injection Fluids 20 AAC 25.402(c)(9) Pt. Mcintyre MI for the Pt. Mcintyre EOR project will be manufactured at the LPC by blending enriching components generated from the vapors in the LPC NGL plant downstream from the feed flash drum with processed reinjected natural gas. Upon full start up of the EOR project, MI manufacture is expected to reach 50 MMSCFD of blended MI with a minimum miscibility pressure of approximately 4350 psi. The expected composition is given in Exhibit H-1.The benefits of additional MI for the EOR project are being evaluated and up to 150 MMSCFD could be injected into the Pt. Mcintyre reservoir as part of the EOR project. Water will be injected alternately with MI in the WAG injection wells to improve the MI sweep in the reservoir. At start up of the EOR project, water injection is anticipated to be approximately 250 MBWPD. Not all of the patterns will be receiving MI simultaneously. Those patterns not initially converted to WAG injection will remain on continuous water injection until MI is available. Source water is currently used for the Pt. Mcintyre waterflood. It is anticipated that the same injection water will be used during the initial stages of the EOR project. Conversion from source water injection to produced water injection is possible in later stages of the flood. Both of these water sources have been approved for injection into the Pt. Mcintyre reservoir under Area Injection Order No. 4B. Injection fluid information pertaining to the amendment of Area Injection Order No. 4B is given below. Type of Fluid - Miscible Injectant. This fluid is an enriched hydrocarbon gas manufactured for the purpose of miscible hydrocarbon EOR. Composition - See Exhibit H-1. Source of Fluid - Natural gas from Pt. Mcintyre, West Beach, North Prudhoe Bay, Niakuk, and Lisburne Pools. Estimated Maximum Amount to Be Injected Daily - Up to 150 million standard cubic feet per day. Compatibility with Formation and Confininq Zones - MI injected into the Pt. Mcintyre pool will be manufactured at the LPC from a mixture of produced fluids from the Pt. Mcintyre, West Beach, North Prudhoe Bay, Niakuk and Lisburne Pools. Based on the current operating practice of injecting processed natural gas from the LPC into the Pt. Mcintyre reservoir and given that the injected MI comprises the same hydrocarbon components in a more concentrated form, no compatibility problems are anticipated. Pt. Mcintyre EOR Project Application 11 . . West Beach 1. Tvpe of Fluid/Source - Tertiary water. The West Beach secondary recovery project will utilize water produced from the Tertiary Sagavanirktok formation (refer to Exhibit G-3 in the "Application for Modification to Area Injection Order No.4", dated April 5, 1993, and attached Exhibit E-1). Composition - A water sample from the target water source interval has not been obtained. However, it is anticipated the water will be of similar composition to that produced from the GC-3 water wells (refer to Exhibits M-1 and M-2 in the "Application for Modification to Area Injection Order No.4", dated April 5, 1993). Electric log salinity calculations from the West Beach State #1 well indicate salinities of 20,000 to 40,000 ppm, which are consistent with the GC-3 water sample analyses and previous log calculations. Estimated Maximum Amount to be Iniected Dailv - Maximum water injection requirements at West Beach are estimated at 10,000 BWPD. Compatibilitv with Formation and Confinina Zones - Laboratory testing, core analyses and geochemical modeling indicate no significant problems with clay swelling or in-situ fluid compatibility. Analysis of the West Beach 4 core indicates significant amounts of clay (11%), primarily in the form of Kaolinite and Illite, which may cause pore plugging in the producing wells at waterflood breakthrough. However, both wells are hydraulically fracture treated, which should help minimize fluid velocities and subsequent fines movement in the rock near the producing wells and the potential for producing well formation damage. The tertiary water is expected to contain excess barium at concentrations from 50 ppm to in excess of 300 ppm, which, if uninhibited, will precipitate barium sulfate scale when mixed with the Pt. Mcintyre water containing excess sulfate (S04) associated with seawater breakthrough. However, the West Beach produced water stream will be inhibited upstream of the PM/WB commingling point to prevent BaS04 precipitation. Because West Beach has not produced any formation water, reservoir compatibility modeling and laboratory testing assumed a water composition similar to that of the Pt. Mcintyre pool. (refer to Exhibit J-3 in the "Application for Modification to Area Injection Order No. 4",dated April 5, 1993) 2. Tvpe of Fluid/Source - Natural Gas. The fluid consists of Lisburne, pt. Mcintyre, West Beach, North Prudhoe, and Niakuk natural gas produced with the oil and separated from the oil and water at LPC. Composition - See exhibit H-2 Estimated Maximum Amount to be Injected Dailv - Maximum gas injection rates are estimated at 25 MMSCFD. Compatibilitv with Formation and Confinina Zones - Although Lisburne processed gas contains H2S, which is not native to the West Beach reservoir, minimal compatibility issues are anticipated. Pt. Mcintyre EOR Project Application 12 . . Section I - Injection Pressures 20 AAC 25.402(c)(10) The estimated maximum and average injection pressures anticipated for the Pt. Mcintyre and West Beach enhanced recovery projects are listed in the following table. Injection Type Estimated Maximum Injection Pressure (psi g) Estimated Average Injection Pressure (psig) Pt. Mcintyre Water Injection Pt. Mcintyre Mllnjection Pt. Mcintyre Gas Injection West Beach Water Injection West Beach Gas Injection 2850 4500 5000 2850 4500 2250 4100 4300 2100 4100 (These pressures represent pump discharge pressures.) Pt. Mcintyre EOR Project Application 13 . . Section J - Fracture Information 20 AAC 25.402(c)(11) The estimated maximum injection rates for Pt. Mcintyre and West Beach enhanced recovery wells will not initiate or propagate fractures through the confining strata, and, therefore, will not allow injection or formation fluid to enter any freshwater strata. There are no indications of injection out of zone for the current water injectors and the single gas injector at Pt. Mcintyre. Freshwater Strata There are no freshwater strata in the area of issue (see Section N of the Application for Modification to Area Injection Order No.4, dated April 5, 1993). Therefore, even if a fracture were propagated through all confining strata, injection or formation fluid would not come in contact with freshwater strata. Enhanced Recovery Existing water injection operations in the Pt. Mcintyre Pool Kuparuk River Formation have been above formation parting pressure to improve recovery of oil. In no instance has such injection pressures breached the integrity of the confining zone. The Kuparuk River Formation at both Pt. Mcintyre and West Beach is overlain by the Kalubik and HRl shales. The HRl is a thick shale sequence which tends to behave as a plastic medium and can be expected to contain significantly higher pressures than sandstones. Mechanical properties determined from log data for the HRl and Kalubik intervals indicate a fracture gradient from approximately 0.8 to 0.9 psi/ft. Fracture data from the Pt. Mcintyre and West Beach Kuparuk River Formation indicate a fracture gradient of between 0.6 and 0.63 psi/ft under virgin reservoir conditions. Fracture data from Pt. Mcintyre No.9 (P2-59) indicated a fracture gradient of 0.624 ps i/ft , while data from West Beach No.4 indicated a fracture gradient of 0.602 psi/ft. The Kuparuk River Formation is underlain by the Miluveach/Kingak shale sequence. A leakoff test in the Kingak shale formation demonstrated leakoff at a gradient of 0.85 psi/ft. In addition, data from the Prudhoe Bay Oil Pool indicate that sandstone fracture gradients may be reduced during waterflooding operations due to reduced in-situ stress associated with the injection of water that is colder than the reservoir. At Pt. Mcintyre, water at a temperature of approximately 70°F is injected into the Kuparuk River Formation, which is at a temperature of 176-184°F. Water injection temperatures at West Beach are also expected to be around 70°F. Pt. Mcintyre EaR Project Application 14 . . Section K - Hydrocarbon Recovery 20 AAC 25.402(c)(14) Pt. Mclntvre Current Pt. Mcintyre operations involve a combination of processed gas re-injection and pattern waterflooding, which is expected to yield an estimated total oil recovery of approximately 42 to 45% OOIP for the Pt. Mcintyre Pool. The planned hydrocarbon miscible EOR project at Pt. Mcintyre is estimated to increase oil recovery by an additional 32 MMSTB of oil, or approximately 6% of the OOIP within the current 15 pattern waterflood area. The existing waterflood patterns contain varied reservoir quality with incremental oil recovery estimates ranging from 4 to 8% OOIP of the targeted oil column under a hydrocarbon miscible EOR process. These estimates are based on analysis of core from 20 wells distributed around the field, detailed field wide stratigraphic correlations, PVT and fluid displacement laboratory studies, and fine scale fully compositional fluid flow reservoir simulations tied back to the laboratory data. The fine scale results were subsequently scaled up to a field wide scale and the expected total incremental oil recovery for the entire waterflood area was calculated using the Pt. Mcintyre Full Field reservoir simulation model. West Beach The West Beach pool is estimated to have originally contained 15 to 25 MMSTB of oil. Reservoir modeling studies indicate peripheral waterflooding should improve expected ultimate recovery by 10 to 15% OOIP, yielding approximately 2 MMSTB incremental oil. The benefits associated with gas injection along the southern bounding fault have not been determined. Pt. Mcintyre EOR Project Application 15 . . Section L - Proposed Findings ARCO Alaska, Inc., as Pt. Mcintyre and West Beach Operator, respectfully requests that the Commission consider adopting the following findings for Area Injection Order No. 4C, which would amend the referenced findings in Area Injection Order No. 4A. 1) Initial enhanced recovery plans for the West Beach Pool call for conversion of one well, WB-06 or possibly WB-04, to water injection. Injection start-up is expected to begin fourth quarter 1999. (Finding No.8, AIO 4A) 2) Fifteen water injection wells and one gas injection well currently exist in the Pt. Mcintyre oil field. ARCO's application includes the locations and mechanical configuration for all current injection wells, and the locations of all existing and abandoned wells within the field. (Finding No. 14, AIO 4A) 3) None of the existing or proposed injection wells in the pt. Mcintyre oil field are within one-quarter mile of the affected area as defined under Conservation Order No. 317A. (Finding No. 15, AIO 4A) 4) Enhanced recovery for the Pt. Mcintyre Oil Pool currently includes fifteen water injection wells and one gas injection well. The waterflood pattern configuration is currently inverted nine-spot on nominal 80-acre spacing utilizing source water, with conversion to produced water injection under evaluation. (Finding No. 20, AIO 4A) 5) Maximum injection rates for enhanced recovery operations in the Pt. Mcintyre Oil Pool are currently estimated to be about 500 MMSCFD gas, 250 MBD water, and 150 MMSCFD of miscible injectant. (Finding No. 22, AIO 4A) 6) Incremental hydrocarbon recovery of approximately 160 MMSTB is expected from the Pt. Mcintyre waterflood and gas injection project, with an additional 32 MMSTB expected from the Pt. Mcintyre hydrocarbon miscible EOR process. (Finding No. 23, AIO 4A) 7) Estimated maximum and average injection pressures (psig) for Pt. Mcintyre gas injection are 5000 psi and 4300 psi; for Pt. Mcintyre water injection, 2850 psi and 2250 psi; and for Pt. Mcintyre MI injection, 4500 psi and 4100 psi. (Finding No. 25, AIO 4A) ARCO Alaska, Inc., as Pt. Mcintyre and West Beach Operator, respectfully requests that the Commission consider adopting the following as findings for Area Injection Order No. 4C. 8) The Commission has issued the following Area Injection Orders and approvals for the Eastern Operating Area of the Prudhoe Bay Unit: Area Injection Order 4 on July 11, 1986, Administrative Approval 4.1 on October 28, 1996, Area Injection Order 4A on August 12, 1993, revised October 4, 1993, a letter approval on July 5, 1994, and Area Injection Order 4B on April 13, 1998. 9) The hearing records and administrative files for the above listed Area Injection Orders and approvals remain valid for the Eastern Operating Area of the Prudhoe Bay Field, and are incorporated by reference into this order. 10) All surface owners within one quarter mile of all proposed injection wells in the Pt. Mcintyre and West Beach fields have been duly notified of the proposed injection project. Pt. Mcintyre EOR Project Application 16 . . 11) Injection of miscible injectant into the EOR project area is scheduled to commence during the first quarter of 2000. 12) Within the EOR project area, 15 current water injection wells will eventually be converted to water-alternating-gas (WAG) service. There are currently 51 producing wells in the EOR project area. 13) If new production wells are drilled within the EOR project area during the life of the project, some existing producers may be converted to injectors and receive MI alternated with water injection. 14) The expected increase in oil recovery from the EOR project is 32 MMSTB, representing approximately 6% OOIP within the EOR project area. 15) WB-04 and WB-06 have been constructed in accordance with 20 AAC 25.030, including obtaining cement bond logs above the target injection interval. Conversion of WB-04 or WB-06 to injection service will be conducted in accordance with 20 AAC 25.412. 16) Injection water for the West Beach waterflood will be produced from the Tertiary sands, defined as strata common to and which correlate with the interval between 2,500' SS and 4,500' SS in the West Beach State No.1 well. 17) Future West Beach Pool enhanced recovery plans may include gas re-injection to displace and capture "attic" oil along the southern bounding fault. 18) To provide artificial lift gas for the West Beach Oil Pool a 4" high pressure line which would accommodate future gas injection has been installed and is in service. 19) Laboratory testing and geochemical modeling indicate the proposed West Beach enhanced recovery fluids are compatible with the receiving formation. Commingling of future West Beach produced water with Pt. Mcintyre produced water may cause barium sulfate scale precipitation in surface facilities. A proactive scale inhibition program should minimize any surface scale. 20) Some increase in the concentration of hydrogen sulfide gas in the West Beach Oil Pool may be expected from the introduction of commingled gas from the LPC. 21) Reservoir modeling indicates continued primary production from the West Beach reservoir during the next year should not adversely affect ultimate recovery. 22) Maximum injection rates for enhanced recovery operations in the West Beach oil pool are currently estimated to be about 10,000 BWPD or 25 MMSCFD gas. 23) Estimated maximum and average injection pressures for West Beach water injection are 2850 psi and 2100 psi; for West Beach gas injection 4500 and 4100 psi. 24) Incremental hydrocarbon recovery of approximately 2 MMSTB is expected from the West Beach waterflood. Benefits associated with gas reinjection have not been determined. 25) All wells drilled within the West Beach oil field have been constructed in accordance with 20 AAC 25.030. All wells abandoned or suspended in the West Beach Oil Pool have been abandoned or suspended in accordance with 20 AAC 25.105. Pt. Mcintyre EOR Project Application 17 . . ARCO Alaska, Inc., as Pt. Mcintyre Operator, respectfully requests that the Commission consider amending Area Injection Order 4B or Conservation Order No. 317A to add the following new rule as Rule 11 or Rule 16, respectively. 26) Rule _ Pt. Mcintyre Oil Pool Enhanced Oil Recovery Project a. Injection of miscible injectant for enhanced recovery operations is approved for the Pt. Mcintyre Pool. b. An annual report must be submitted to the Commission detailing performance of the Pt. Mcintyre Oil Pool Enhanced Oil Recovery Project and outlining compositional information for the current miscible injectant (MI) necessary to maintain miscibility under anticipated reservoir conditions. ARCO Alaska, Inc., as West Beach Operator, respectfully requests that the Commission consider amending either Area Injection Order 4B or Conservation Order No. 311A to add the following new rule. 27) Rule 12 West Beach Oil Pool Annual Reservoir Report An annual West Beach Oil Pool surveillance report will be required by June 1 of each year starting in the year 2000. The report shall include but is not limited to the following: a) Progress of enhanced recovery project(s) implementation and reservoir management summary including engineering and geotechnical parameters. b) Voidage balance by month of produced fluids and injected fluids. c) Analysis of reservoir pressure surveys within the Pool. d) Results and, where appropriate, analysis of production logging surveys and tracer surveys. e) Results of any special monitoring. f) Future development plans. Copies of annual progress reports and plans of development for the West Beach Participating Area filed with the State of Alaska will fulfill this requirement. If additional information is required a request will be made by the Commission within 30 days. Pt. Mcintyre EOR Project Application 18 . . Section M - Recommended Conclusions ARCO Alaska, Inc., as Pt. Mcintyre and West Beach Operator, respectfully requests that the Commission consider adopting the following as its conclusions. 1) The requirements of 20 AAC 25.402 and 20 AAC 25.460 have been met for the injection of fluids for the proposed Pt. Mcintyre Oil Pool and West Beach Oil Pool enhanced recovery operations. 2) Revising Area Injection Order No 4B to include the West Beach oil pool area is appropriate for authorizing injection of fluids for enhanced recovery operations in the West Beach oil pool 3) Revising Area Injection Order 4B to incorporate the West Beach oil pool area will not cause waste nor jeopardize correlative rights. 4) No underground sources of drinking water (USDW) are known to exist in the Eastern Operating Area of the Prudhoe Bay Unit, the Pt. Mcintyre oil field, and the West Beach oil field. 5) Amending Area Injection Order No. 4B is appropriate for authorizing injection of fluids for enhanced recovery operations in the Pt. Mcintyre, Stump Island and West Beach Oil Pools. 6) Implementation of the Pt. Mcintyre hydrocarbon miscible EOR process via the Pt. Mcintyre EOR Project involves the application of a tertiary enhanced oil recovery method in accordance with sound engineering principles. 7) The application of the Pt. Mcintyre hydrocarbon miscible EOR process is expected to result in an increase in ultimate hydrocarbon recovery. 8) The proposed Pt. Mcintyre hydrocarbon miscible EOR process will be undertaken in areas of the Pt. Mcintyre oil pool where tertiary activities have not been applied previously. 9) Additional drilling within the EOR project area may be undertaken to improve sweep in areas of the reservoir unaffected by the hydrocarbon miscible EOR process and to result in the recovery of oil from areas and reservoir volume not otherwise affected by the implemented tertiary recovery activities. 10) Injection operations in the Eastern Operating Area of the Prudhoe Bay Unit, the Pt. Mcintyre Oil Pool and the West Beach Oil Pool will be conducted in permeable strata which can reasonably be expected to accept fluids at pressures less than the fracture pressure of the confining strata. 11) Specific approvals to convert or drill injection wells will be required. Pt. Mcintyre EOR Project Application 19 . . Section N - Requested Decisions ARCO Alaska, Inc., as Pt. Mcintyre Operator, respectfully requests that the Commission issue an order authorizing the underground injection of miscible injectant for enhanced oil recovery for the proposed Pt. Mcintyre EOR Project. ARCO Alaska, Inc., as West Beach Operator, respectfully requests that the Commission issue an order authorizing the underground injection of Class II fluids for enhanced oil recovery into strata defined as those which correlate with and are common to the formations found in the West Beach No.4 well between the depths of 14,458' MD and 14,781' MD. Pt. Mcintyre EOR Project Application 20 . . Exhibit A-I Ir~~- . --"._~ I I; t\ . ': , JB CI) ,11 (1) 1'/ .5 Ii III ~ I Co Q.. = -= ~ ~ t)¡) :Q = - CI) .- ~ .. = ~ ~ ~ ~ = .- - ~ ~ · Q\ Co · ~g. ~ · I»~ "CI · I ~8 = · ""'..... = Æ~ · CO CI.I ~~ ~ · .. .- · CI.I - · - .- ... Q = ~ ... < ~ 0 ~ ~ ... ~ ~ .. à C c - - ~ Cj ~ CI) '(1) ð:: .5 . ~& .. Q.. ~o: ... · ~ .. · = · ~ ... · -. ~ · I · · · _....._~~ . · .w'¡' Exhibit A-I I: I' I ~ ::J' C' ;:; j m ! . ..... . "',11> Ii i -/ '?I!I~ .. I· ''M,e,,, -··T-- "'.11I> ~._ --. I - - ···-·1·-- ......,. ,-. . i i .., ea. I" ! i .. ; ! .1. ..... . I: i .. 1i'J.:r ON :j-:] f /'/ S 4.f~,2 ,;: P2-14td. P2-d:. BPX pZ-IB~4P¡ J i -30-96 · · PZ-:8f12 ADL 365548 ~ I: .. II p.f-e2 . Pol-69 . Pa-08 .. P2-18 . P3-40 . Pt.-fa PB-4f1 .. ~ . n-'!s P2-!7 P2-28 .. . A 1'2-83 -¢- tit PI-'.-f2 "'" . Fa-58 . P2-21 . n-J/s . PI!-60 . i I' I P2iB Pz-,~ __ _ P..3~~ TDP2-f"r -. .·f.2~. . .. -48 ¥I, P~ON iJ6.1t....7?' P.-¡tK860 1!,! -4.lJLpf-1Ê24 .. ;Ul, 1¡"'){XON 3~8-77 ÁLt862 A.DIfi&162ï ~.,;.~.~,,;.,,;.... P2-$()' . ¡PiLr . . ¡ T' 'II> 'R.e.. . .--.L_.._._.___L... ....- ""..... f no,.,. "NU' ",.,"" tt:ft"~'*1I. .-. - -.... 1mIIUI1Ii"'" J I .1 . t--fS ICIUI AZ._ Plat of Wells Within Pt. Mcintyre Participating Area . ~ 2: C' ;:; m . ..... . . Minimum Last State Last ARca Next MIT Injection Well Packer Depth T t P Witnessed es ressure Test MIT Scheduled Name API (Feet tvdss) (psi) (Date) (Date) (Year) P1-G1 500292229800 8199 2050 06/21/97 06/21/97 2001 P1-01 500292201800 8385 2096 None 05/11/98 2002 P1-14 500292233800 8328 2082 07/06/98 07/06/98 2002 m P1-16 500292234900 8641 2160 07/06/98 07/06/98 2002 m >< P1-21 500292236300 8610 2153 07/06/98 07/06/98 2002 >< ::r ::r C" P1-25 500292193700 8750 2188 07/06/98 07/06/98 2002 C" ;:¡: P2-09 500292287600 8846 2212 02102/99 02/02199 2003 ;::¡: IXJ IXJ I P2-15 500292240900 8870 2218 09/29/98 09/29/98 2002 I I\) I\) P2-16 500292239700 8742 2185 09/29/98 09/29/98 2002 P2-23 500292245300 8850 2213 07/06/98 07/06/98 2002 P2-28 500292255100 8860 2215 08/08/95 08/08/95 1999 . P2-29 500292240700 8685 2171 None 03/17/98 2002 P2-34 500292255800 4948 1500 08/23/98 08/23/98 2002 P2-42 500292240500 8702 2176 07/06/98 07/06/98 2002 P2-46 500292240100 8286 2072 07/06/98 07/06/98 2002 P2-47 500292262800 8480 2120 06/13/96 06/13/96 2000 Pt. Mcintyre Injection Wells ~ <')- r CULL IS ST .' / ",/ tr1 ~ =:T ~. cT ~. ~ + + / I + . + + tr1 ~ =:T ~. cT ~. ~ . irB ST1>LC:~(;8 . / /"" LCI-06 LCI-'1'2/ ./ \ \... \ \. \, . \ ! CULL ~S ST 2LS -~S " + tt~t,.l."., t:C I W t:C I W , ,// )F>,,/ // / / /!' /:<)/1 ,,' / ,/ (1]7'02 <~/ AAI, EXXON ~l:1;;lt LI-30: ,,"Wl:M3~~8 Ii ":;",,,.-,,,,.,.,....' LS:-23 i;;~ . + L5.LÓ!'t19 :;J. , --~::::::::::::^J:::.::m:.< S-rL 6 + L5-15 """':',",~"~.""'~ Plat of West Beach Pool/Participating Area (Possible Injection Wells are WB-04 or WB-06) . . + + I I SCALE IN MILES o I 36 EGG ISI).IoD :"\ ') ~ I 6 STUMP IS1.AND + + USS4044 USS9267 FF¥-954 WEST DOCK + USS6906 FF11322 N P8 STAlE #1 o . 0, ~ ~ xlJ "" 0 \) a Î\~~',..,~\J "'" 'Vo ~~ ~D \1~\~"-1, ~, Q \)\ \J "J' ~ 0 n o~ ()~\)".(,~" \,¡:"""-"'" \) \.........., Ii, ~~; ....\ ';) ðtJ~ 2 I LG LG M ~~)â ~ ~ pt. Mcintyre Area Allotment Location Map NORTH SLOPE ALASKA QQ ::~ ß r '. ~ Exhibit C-l . . Exhibit D-1 Affidavit STATE OF ALASKA THIRD JUDICIAL DISTRICT I, J. W. Groth, declare and affirm as follows: 1. I am the Supervisor of Eastern Satellite Development for ARCO Alaska, Inc., the designated operator of the Eastern Operating Area of the Prudhoe Bay Unit, and as such have responsibility for West Beach and Pt. Mcintyre operations. 2. On ~ P1ß£/L 8 , 1999, I caused copies of the Application for Injection and Amendment to Area Injection Order No. 4B with regard to the Enhanced Oil Recovery Project in the Pt. Mcintyre Oil Pool and the Secondary Recovery Project in the West Beach Oil Pool to be provided to the following surface owners and operators of all land within a quarter-mile radius of the proposed injection areas: Operator: ARCO Alaska, Inc. Attention: Mr. J. W. Groth P.O. Box 100360 Anchorage, AK 99510-0360 Surface Owners: State of Alaska Department of Natural Resources Attention: Mr. Mike Kotowski P.O. Box 107034 Anchorage, AK 99510 Exhibit D-1 . . Selection within Section 28 CADL 414852) City of Barrow City of Barrow P. O. Box 629 Barrow, AK 99723 Parcel 16 CUSS 9137) Lawrence Ahmaogak P.O. Box411 Barrow, AK 99723 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Parcel 16 CUSS 9267) John P. Nicholls (minor) C/o Ely Varner (guardia) P.O. Box 473 Barrow, AK 99723\ And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Parcel 17 CUSS 6905) Alice Glenn 899 Blair Ave. Sunnydale, CA 94087 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Exhibit D-1 . . George Ahmaogak P.O. Box 338 Barrow, AK 99723 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Lawrence Ahmaogak P.O. Box411 Barrow, AK 99723 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Parcel 18 CUSS 6906) Barbara Ahmaogak, Life Estate Holder 1628 Hilton Ave. Fairbanks, AK 99701 And C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 Lawrence Ahmaogak, George Ahmaogak and Alice Glenn, remaindermen (service as provided above) Exhibit D-1 . . Parcel NA F-14632 Wallace Oenga, Georgene Shugluk, Leroy Oenga, Michael Delia and Jennie Oenga (deceased, probate pending) C/o Kathleen Dickinson, Land Director Arctic Slope Native Association, Ltd. 714 Fourth Ave., Suite 201 Fairbanks, AK 99701-4470 USS 4044 United States Department of the Navy U.S. Dept. of Navy Commanding Officer (Code 05LM) Engineering Field Activity NW Naval Facilities Engineering Command 19917 7th Ave., NE Poulsbo, WA 98370-7570 Dated: ¿ wrLJ.1£/L g ,1999. /~ ~-V Lï~~ J. W. Groth Declared and affirmed before me this ~ day of \\ \) ~ -t \\A..I\7JL Ý , 1999. (killLCv¡ \S 'ßL\~&L \ \. Notary Public in and for Alaska My commission Expires: : OJ \ \ I CÙ Exhibit D-1 . Subsea Depth Alternate Completion Interval 3000 if needed to augment water supply 4000' SV2 Initial Open Hole Gravel Pack Completion Target for Sourcing Water 4500 . Exhibit E-l West Beach Shallow Section Type Log WB-l O"IIIII)I.stll.' ~~ f.--"i. <$ ~ ~~~~ ~ ~: ~~ .;.1 --~ >- ~ ~ "'-..- -=..?~ .ç -~~ ~- '"i,,- _4 .~..~ ~ ~;;;. .~, -..,.. ...~~ ....,.-- ~ -"~ . tr1 tr1 ~ ~ þ"' þ"' ~. ~. cr cr ~. ~. r-t'- r-t'- ~ ~ I I N N . "'î -- -ï .... ....".._._~ ........-.... Post WB6 Net to Gross _..._~ West Beach Reservoir Net-To-Gross Ratio Map Post-Drill West Beach 6 using an 8% porosity cut-off . . Exhibit F-l ~, tn ~:<>- ~ '" 1 ~ = 1 0 ... - CJ ~ rJ'j I ~x rI.I rI.I ~ 0 .. u CJ ... .= i c.. = .. O!) ... - . = 1 .. - ~ = ~o .. = - CJ = .. - rJ'j t - rI.I = ¡¡¡ ~ ~ 0 æ - ~-<? - ~ rI.I ~ ~ .c CJ 1 = ~ ~ - rI.I ~ ~ ~ 1 -5 ~, Æ :1-9- '" 5: ~ c i <n >< ~ ::> ~ êñ Exhibit F-l ftKB 2182 21~ I ~ 8280 8261 6316 8319 8369l 8370 l H , 8397·1 I C 8420 I M,,- - 8432 J I I 84331 ----¡ 8640 -I 86601 8680 ~ 8700 -1 WRSSSV ---,- . . Exhibit G-1 Pt. Mcintyre Well Schematic Conventional Gas Injection Well Design - P1-G1 XO NIP PKR NIP NIP TT Pert -_ I P1-G1 API: 500292229800 S ud: 02-Nov-92 H2S: Orig Canpltn: 19-Nov-92 39' MD Btm Feet Descri tion 3485 3485 SUR. CASING 8607 8607 PROD. CASING 8840 419 LINER. 13CR. FOX Vlv Vlv Run ::ommen ! GLM ~~-------~_.~ J Exhibit G-1 Pt. Mcintyre Well Schematic Conventional Water Injection Well Design - P2-47 ftKB-C---- 8 =-" 113744 J 13745 14985 ~ 14~j 15005 15006 - 15029 15030 15040 15041 I i 150511 150521 , , i 16176 J I I I 16177l I I ~ , 16400-i ! 16600 I 16800 ~ . NIP PKR NIP NIP TT PKR Perf . Exhibit G-2 P2-47 ~~¡:>L 5002922628oor__SPUd: 08-0ec-95 -~TQ:V~9QO ItKB ___ H2S: . Orig Compltn: 107-Feb-96 Max Hole 164 deg @ 6966 , Angle~~_ SSSV T Last W/O: An Ie TS: d Ann~~~~1e~~~~ö~ R~ L~~~I~~a;~~mmm .._ ~~-~~;rd=~~Og- Last Tag: 1604T Last Update: 27-Jun-Q8 , DEEPEST . DRIFT Rev Reason: ,SCH REVISON -We.IT-INJ mm Safe Notes Date Note 07-Feb-95 . Minimum 10: 3.725" HES XN NIPPLE AT 15040' Mo General Notes Date Note 07-Feb-95 I Well Status: ACTIVE Öi:Fe&:95Ttuh¡n-"'~r----- :--¡='M'C'"NS"@"j5'Mo" . --------.---~--~.- Last T D 16900 T Of Fluid D th 16054 Casin Stri " All SID 'We' ht Grade 13318 '68.00 LBO 9 518 47.00 LBO 7 26.00 L80 41/2 12.60 LBO 4 1/2 12.60 L80 4 1/2 12.60 L80 Tubing, Strin s - Ail SIZe We. ht Grade 41/2 12.60 L80 Gas Lift MandrelsNalves t MD TVD, Man Man Mfr Type RKB: 52 It KÒÞ ofiKä To o o 13816 16176 16877 16308 Btm 4721 13979 16328 16308 16900 16877 Feet'Desert 'on 4721 SUR. CASING 13979 PROD. CASING 2512 PROO. CASING 132' PROD. CASING 23 PROD. CASING 569 SLOTTED LINER To o Btm 15051 Feet Descri tlon 15051 TUBING Vlv Vlv Run ;ommen GLM . -------- Exhibit G-2 ftKB 2255 2256 ...~ 4806 11597 11598 11634 NIP 11635 - 11655--1 ì 11656l \ I B , ,,""J I . I 11706-J I . I 11689l ! 11727-1 TT I 11728-1 I . I 11800 -! Perf . I 11810-" i 11820-1 L- i Perf 11940. i 11960, TRSSSV . . Exhibit G-3 pt. Mcintyre Well Schematic Slimhole Water Injection Well Design - P2-15 NIP NIP P2-15 API: 500292240900 S~.cI.: ~~·Feb-94 ---¡:¡zg:.- Ori9 Campltn: '08·Mar-94 PBTD: 12210 ftKB Max Hole· 48 deg @ 4042 Angle: A Ie TS: d . J\"9.Ie@TD:.45¡eg@J222() Last WIO: RefLogPate 05-Mar:94 .. u. LastTag 21-Ju~94 Date: Last U ate: 27-Jun-98 RKB: 47 ft KOP: -0 ftKB 11705' MD 28'MD -_._-._._._--~.-.. Vlv Vlv Vlv Vlv Vlv : VIv Vlv Mfr! Type Latch Port TRO· Run me T 48050TI 9 OTIDM-I4RIBK 0 0.0' GLM 2 11597 11597 OTIS- 9 aT' DM-14R BK 0 O~O GLM Other lugs. equip", etcJ - JEWELRY De th Type i Description 2255 Tf!~.§'\Il4::1/2'· CJ>.MCO T.RºF'§~\I,lQ.=3.81£:..__~_ 11634 NIP : OTIS X NIPPLE, ID=3.813" 11555 PKB--J 7-518" X 4-112" BAKER SABL-3 PACKER 11689 NIP I OTIS X NIPPLE, 1()=3.813'· 11705 NIP I OTIS XN NIPPLE, ID=3.75" 11727 T~TUBfNG·TÁIL.WŒG~-1i714'-ECMD- Perforations Summa Interval Zone SPF . Date ' T e Comment 11790-11830 621-Ju~94 11920 - 11970 6' 21-Jul-94 Exhibit G-3 . . Exhibit G-4 pt. Mcintyre Well Schematic Ultra Slim hole Water Injection Well Design - P2-09 ftKB 500- 1000- 1500.., 2000- SSSV NIP WRSSSV _/ 2500 ~ 3000 - 3500 ~ 4000 - 4500 - 5000 - 5500 - 6000- 6500 - 7000 - 7500 - 8000 - 8500 - 9000 - 9500 - 10000 - 10500 - 11000 11500 12000 - PKR NIP - NIP - 12500- TUBING - TAIL P2-09 SL .- ----- API: 500292287600 H2S: S ud: 19-A -98 Orig Compltn: PBTD: 12537 ftKB Max Hole 56 deg @ 11600· An Ie: Angle@ TS: ~___ Angle@ TO: 51 deg @ 12537 _Q.S§.'UY!"" Last W/O: Annular Fluid: Diesel to 4000'. Ref Log Date: 11-Jun-98 SW 4000'-11899' Reference SWS CET L :, Lasl Tag: 12350" SLM-GORR Rev Reason: INITIAL PERFS - WellT '!T"'¡:¡-- Saf Notes Date Note 11-M 98 MIN. ID: 3.75' HES 'XN' NIPPLE 11943' Casing. Stri-"gs - All Size We' ht Grade 7 26.00 9~40.oo Tubing Strings· All Si~_--, Weight I Grade 4 1/2 ·12.60 . Gas Lift MandrelsNalves 11 MD, TVD' Man I~n Vlv Vlv Mfr I Type Mfr Type 4553 4553 CAMeO KBG-2-LCA DK-1 LastTag 08-Jul-96 Date: Last Update: 11-Jul-98 RKB: Oft KOP: 0 ftKB To Of o Btm 12509 5695 Feet Oeser! . on 12509 Casing 5695 Casi ~~¡~on o 11955 11955TTubing I -; VIv Port Vlv TRO VIv! Vlv Run pommen Vlv Latch T e BTM INT BTM INT 0.0 -May-98 , o 0.0 -May-98I 11832, 11632 CAMeO KBG-2-LCA DK-1 o Other (plugs, equip., etc.) - JEWELRY ---1 De"I.I1.f!YPL__~~!iption I 2040 I SSSV 4.5" BAL-O SVLN _J---lliIP 20451 WRSSS\ OOH - DUMMY PULLED 6110/96 L 1.1699jPI<.R___I3t-KE_R_7"" s,~P_ER~"'\Er\rrF'~ÇKER ! 119321 NIP HES 'X" NIPPLE -,------~~------"--- -----------~---- , , --;'T9431 NIP HES "XN" NIPPLE ! 119551¡TUBING TUBING TAIL WIWEG 11964' ELM) I TAIL Perforations Summa Interval Zone 12050 - 12070 I I 112116 - 12166 112264 - 12264 I I i ¡ ! ! I I I I I Status i Feet, SPF Date ,Type i Comment i 20, 6 18-Jun-913-3I6"" 160 degree I :HJ" , phasing: :RDX ! proposed L I squeeze I~S j 50 6 11-Jul-963-3I8"" 160 degree iHJ" ¡ phasing: :RDX UC4,3.2 I 20 6· 11-Jul-98 3-318"" 160 degree I HJ" phasing: UB1 ¡ 'RDX ¡ I Exhibit G-4 ftKB 2091 - SSSV NIP 2092.., 6231 ~ 6232-1 6383 - 6384 ~ 12820 - NIP 12821 - Perf 12900 - 12905 - 12910- 12915 12920 - Perf 13080 - 13090 - 13100 - 13110- . . Exhibit G-5 Pt. Mcintyre Well Schematic Mono-bore Water Injection Well Design - P2-34 PKR P2-34 PBTO: 13326 ftKB Max Hole' 55 deg @ 8279 An Ie: An Ie_@ TS d ~!lle @ TO: 49 d 13327 ...m.__.________._____~.__ .--....--.........-...----.- Feet! Descrl~ 6533 PROD. CASIN!3 I 1 6231 6231 HE5-LB OT D- 14R OtIte~(plu.9!l.J!Cui~ etc,t: JEWELRY De th· T e Deserl tion 2091. SSSV 5-112" PARKER SWS NIPPlE. 10=4.562" NIP 6383 PKR 9-5/a::_X_~.:!ª':_ê~KER_UNEBl()~2XP PACKEB___. -c--12820NlP- PARKER SWS NIPPLE. ID=4.562'· Peñorations Summa Interval Zone : Status Feet SPF Date ! T e Comment 12896 -12921 25 6 01-Au -9 13070 -13120 50 6 01-Au9- Exhibit G-5 Well: WB-04 ftKB 2281 SSSV 2282 4771 4772 8735 8736 11208 11209 12536 12537 12936 12937 13056 PKR 13057 13145 14124 NIP 14125 14430 14431 . TT GPMA . WEB Date: 4/15/99 WB-04 API: 500292211700 SSSV Type: CAT 1- SSSV Annular Fluid: 30000 DI Reference GR/DIULDT/CNL Log: Last Tag: 14910 Last Tag Date: Angle @ TS: deg @ Angle @ TD: 31 deg @ 1491 Rev Reason: Last Update: 5/19/98 Well Type: PROD Orig Compltn: 8/8/91 Last W/O: Ref Log Date: 6/6/91 TD: 14909 ftKB Max Hole 65 deg @ 9400 An Ie: Safe Notes Date Note 6/15/91 Minimum ID: 2.750" OTIS 'XN' NIPPLE 14124' MD General Notes Date Note 6/15/91 Tubing Hanger: RKB @ 25' MD 6/15/91 Well Status: ACTIVE Last Tag Depth @ 14910 To Of Fluid De th 14549 Other lu s, e ui ., etc. - JEWELRY Depth TVD Type Description 2281 2243 SSSV 3-1/2" OTIS FMX SC SSSV, ID=2.813" 130567691 PKR 9-5/8" x 3-112" BAKER 'D' PACKER 141248442 NIP OTIS XN NIPPLE, ID=2.75" 14430 8696 TT TUBING TAIL ELMD 14428' ELMD Casin Strin s - All Size Weight Grade 13.375 72.00 L-80 9.625 47.00 L-80 7.000 29.00 L-80 5.000 18.00 13CR Tubin Strin s - All Size Weight Grade 3.500 9.30 L-80 3.500 9.30 13CR Gas Lift MandrelsNalves Stn MD TVD Man Man . V Mfr V Type V OD Latch Port TRO Mfr Type 1 4771 3925 CAMCO MMG (9CR) 2 8735 5742 CAMCO MMG (9CR) 3 11208 6839 CAMCO MMG (9CR) 4 12536 7431 CAMCO MMG (9CR) 5 12936 7625 CAMCO MMG 9CR ID 2.81 3.00 2.75 4.0C Top o o 13145 14208 Feet Description 4928 SUR. CASING 13443 PROD. CASING 1363 LINER 701 LINER Btm 4928 13443 14508 14909 Top o 14147 Feet Description 14147 TUBING-IPC 299 TUBING Btm 14147 14446 Date Run Vlv Comm GLM CA RK 0.000 o RD 1.5 RK 0.000 o GLM CA RD 1.5 CA RD 1.5 RK 0.000 o GLM GLM CA RD RK 0.000 o 1.5 CA E RKP 0.000 o GLM 1.5 Perforations Summa InteNal TVD 14550 - 8798 - 8840 14600 14620 - 8857 - 8954 14734 14754 - 8971 - 8988 14774 Status Feet SPF Date Type Comment 50 4 7/4/91 114 4 6/30/91 20 4 7/3/91 14560 Perf 14580 14650 Perf 14700 Perf 14760 14770 Exhibit G-6 Well: WB-06 ftKB SSSV 2010 2600 2605 ~ 7020 ~ I 7250 -j 9505 12190 12195 14595 16305 17235 17298 NIPPLE 17299 17309 PKR 17310 17311 ~ 17312 17372 NIPPLE I 17373 J 17374 I ! 17393 NIPPLE 17394 17404 17405 17900 18000 I I 181121 18700 ~ IT FRAC FRAC FRAC RFT PARTS . GPMA SL WB-06 API: 500292292900 SSSVType: CAT I Annular Fluid: Diesel & Seawater Reference Log: Last Tag: 16213' SLM Last Tag Date: 6/12/99 . WEB Date: 6/16/99 Well Type: PROD Orig Compltn: Last W/O: Angle @ TS: deg @ Angle @ TO: 55 deg @ 18212 Rev Reason: High tag (carbolite) Last Update: 6/13/99 Ref Log Date: TD: 18700 ftKB Max Hole 69 deg @ 10979 An Ie: Top o o 13694 15814 16913 Btm 7261 13694 16042 16913 18210 Feet Description 7261 Surface 13694 Intermediate 2348 Intermediate 1099 Production 1297 Production Notes Date Note 2/2/99 Minimum ID = 3.725" at XN nipple 17393' MD. 3/16/99 Frac Sleeve 2.9" ID 49'Ion set on 3/14/99 1975' SLM General Notes Date Note 1/24/99 In additions to the IPERFs on 3/3/99, there was also 9 shots taken between 17608-18006 dUl a 5WS RFT. Fish - FISH Depth Description Comment 18111 RFT PARTS RFT BOLTS other lu s e ui .,etc. - JEWELRY Depth TVD Type Description 2008 1986 SSSV CAMCO 4-1/2" TRM-4E TRSSSV 17298 8760 NIPPLE X NIPPLE 17309 8765 PKR BAKER T' X 4.5" MODEL S-3 HYDRO SET PACKER 17372 8797 NIPPLE X NIPPLE 17393 8808 NIPPLE XN NIPPLE ( wI C-SUB ran 5/23/99) 17404 8814 IT BAKER WLEG 17405' ELMO Casin Strin s - All Size Weight Grade 13.380 68.00 L-80 9.630 47.00 L-80 9.630 47.00 L-80 7.000 29.00 L-80 7.000 29.00 13CR-80 Tubin Strin s - All Size Weight Grade 4.500 12.60 L-80 Gas Lift MandrelsNalves Stn MD TVD Man Man Mfr Type 1 2599 2516 CAMCO MMG 2 7017 4603 CAMCO MMG 3 9501 5617 CAMCO MMG 4 12188 6612 CAMCO MMG 5 14592 7604 CAMCO MMG 6 16300 8304 CAMCO KBG-2 Top o Btm 17405 Feet Description 17405 Tubin VMfr V Type V OD Latch Port TRO CAMeo DMY 1.5 CAMCO DMY 1.5 CAMCO GLV 1.5 CAMCO DMY 1.5 CAMCO GLV 1.5 CAMCO MEMORY 1.0 GAUGE KBG-2 CAMCO OV 7 17231 8726 CAMCO Perforations Summa Interval TVD 17860 - 9060 - 9188 18090 Stimulations & Treatments Interval Date Type 17860 - 18090 3/6/99 FRAC 17860 - 17967 3/17/99 FRAC 17860 - 17967 5/19/99 FRAC RK 0.000 0 RK 0.000 0 RK 0.250 2496 RK 0.000 0 RK 0.000 2471 BK 0.000 0 1.0 BK 0.250 ID 3.81C 3.810 3.880 3.810 3.72C 4.000 Date Run 6/3/99 5/15/99 5/25/99 5/16/99 5/25/99 5/26/99 Vlv Comme o 5/27/99 Zone Status Feet SPF Date Type Comment o 230 4 3/3199 ¡PERF 60 deg phasing Comment 30,000 Ibs of 20/40 LWP 38,400 Ibs of 20/40LWP 124,655 Ibs or 20/40 LWP Exhibit G- 7 . Exhibit H-1 . Pt. Mcintyre Miscible Injectant Compositional Analysis Component Nitrogen Carbon Dioxide Methane Ethane Propane Iso-Butane N-Butane Iso-Pentane N-Pentane Hexane Heptane Plus Mole Percent 0.41 9.26 58.01 11.76 16.15 1.70 2.49 0.12 0.08 0.02 0.00 Exhibit H-1 . Exhibit H-2 . Component Hydrogen Sulfide Carbon Dioxide Nitrogen Methane Ethane Propane I-Butane N-Butane I-Pentane N-Pentane Hexane + Specific Gravity LPC Reinjection Gas Value Unit 40 ppm 7.34 mole % 0.65 mole % 79.88 mole % 7.3 mole % 3.75 mole % 0.39 mole % 0.62 mole % 0.04 mole % 0.03 mole % o mole % 0.7171 Composition from 9/26/97 Sample # 44590 Exhibit H-2