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Home My WebLink AboutCO 317 BIndex Conservation Order 317B Pt McIntyre and Pt McIntyre and Stump Island 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 12, 2000 Transcript of hearing, testimony, sign in sheet 6. March 9, 2000 Ltr from Arco answering questions from hearing 7. September 9, 2003 BP request to Commingle Production from Pt. McIntyre Participating Area with IPA Production 8. October 16, 2003 DOR response to BP's request 9. October 27, 2003 DNR response to BP's request 10. November 11, 2003 Revised BP request to Commingle Production from Pt. McIntyre Participating Area with IPA Production 11. January 27, 2004 DNR revised response to BP's request 12. May 23, 2007 Annual Surveillance Reporting Requirements (C031713- 002) 13. February 20, 2020 BPXA's request for Amin Approval for Conforming PBU Greater Pt. McIntyre Area Satellite Pool Rules for Consistency (CO 31713.003) 14. February 24, 2020 BPXA Request to amend CO 492 rule 3(a) and 6(a) (co317B.001) 15. May 21, 2020 Notice of Hearing and mailing 16. ----------------- Emails Index Conservation Order 317B Pt McIntyre and Pt McIntyre and Stump Island Oil Pool 1. November 8, 1999 2. November 20, 1999 3. December 1, 1999 4. January 1, 2000 5. January 12, 2000 6. March 9, 2000 7. September 9, 2003 8. October 16, 2003 9. October 27, 2003 10. November 11, 2003 11. January 27, 2004 12. May 23, 2007 Arco Alaska's Pt McIntyre Application to Amend A104B 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 BP request to Commingle Production from Pt. McIntyre Participating Area with IPA Production DOR response to BP's request DNR response to BP's request Revised BP request to Commingle Production from Pt. McIntyre Participating Area with IPA Production DNR revised response to BP's request Annual Surveillance Reporting Requirements (C031713- 002) Conservation Order 317B go STATE OF ALASKA 400 OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: The application of ARCO Alaska, Inc. ) Conservation Order No. 317B ("AAI") to amend AID 4 to initiate a Miscible ) Gas Enhanced Oil Recovery Project in the ) Pt. McIntyre Oil Field Prudhoe Bay Unit, Point McIntyre Oil Pool, ) Pt. McIntyre Oil Pool (amended) North Slope, Alaska. ) Stump Island Oil Pool April 19, 2000 IT APPEARING THAT: By correspondence dated November 8, 1999, AAI requested authorization from the Alaska Oil and Gas Conservation Commission ("Commission") to initiate a miscible gas tertiary recovery project in the Point McIntyre Oil Pool located in the Eastern Operating Area of the Prudhoe Bay Unit. The Commission published notice of opportunity for public hearing in the Anchorage Daily News on November 20, 1999. The Commission did not receive a protest or request for a public hearing. The Commission held a hearing at the Commission's offices on January 12 and 13, 2000. FINDINGS: The Commission has issued Conservation Order No. 317 dated July 2, 1993 (revised September 10, 1993) and Conservation Order No. 317A dated April 25, 1996 to govern development of the Pt. McIntyre Oil Pool. 2. The findings, conclusions and administrative records for the above listed Conservation Orders are incorporated by reference in this order. 3. AAI is the operator of the Eastern Operating Area of the Prudhoe Bay Unit including the Point McIntyre Oil Field and the West Beach Oil Pool. There are no other operators within a one-quarter mile radius of the proposed injection operations. 4. The State of Alaska is the only surface owner within one mile of the Point McIntyre Oil. Facility modifications at the Lisburne Production Center (LPC) are designed to ensure that the volume of natural gas liquids extracted at the LPC will not be impacted by the manufacture of miscible injectant solvent. 6. AAI proposes to use hydrocarbons from the Pt. McIntyre, West Beach, North Prudhoe Bay, Niakuk and Lisburne Oil Pools processed in the LPC. Components from the natural gas liquid plant downstream from the feed flash drum will be added to enrich the miscible injectant (MI) stream to be used in the Point McIntyre enhanced recovery project. 0 Conservation Order No. 30 010 April 19, 2000 page 2 7. Seventy-four producing and service wells were active in the Point McIntyre Oil Pool (PMOP) as of January 1, 2000. Fifteen water injectors and one gas injector were providing pressure support to the PMOP, maintaining average reservoir pressure near the original pressure of approximately 4370 psi. 8. The inverted nine -spot waterflood pattern in the PMOP is flexible and can be adapted to changes in reservoir performance as the enhanced recovery process matures. The PMOP miscible gas injection project involves conversion of present and future waterflood injectors to water -alternating -gas (WAG) injection service. 10. A MI slug equivalent to approximately 35 percent hydrocarbon pore volume (HPV) will be placed over a twenty-three year period. 11. The maximum MI rate that can be manufactured from LPC residue gas is projected to be 50 MMSCFD at a minimum miscibility pressure of approximately 4350 -psi. 12. An extensive performance history indicates that the Pt. McIntyre waterflood has been able to adequately balance voidage in the reservoir to maintain an average reservoir pressure of 4370 psi. 13. The minimum miscibility pressure is designed to be as close to average reservoir pressure as possible. This will maximize the volume of MI that can be manufactured at LPC. 14. Limited supply of MI will require phased implementation and conversion of patterns to WAG injection. Any volumes of MI in excess of the nominal 50 MMSCFD rate injected in the PMOP will have to be purchased from an external source. 15. The benefits of using additional MI, up to 100 MMSCFD purchased from an external source for this project, are being evaluated. 16. Modifications at LPC done in 1999 to manufacture MI included installation of an MI compressor, a new parallel chiller, new compressor coolers, blending station, and an upgrade of the natural gas liquid plant piping. 17. MI will be transported to the Point McIntyre drill sites by a new pipeline using existing vertical support members and new drill site distribution piping. 18. The geologic description of the injection and confining zones for both the PMOP miscible gas tertiary recovery project and the West Beach Oil Pool (WBOP) enhanced oil recovery project have been previously submitted in "Application for Modification to Area Injection Order No. 4" dated April 5, 1993. 19. Injection wells in the PMOP have been drilled, cased, cemented according to requirements of 20 AAC 25.005 and tested according to 20 AAC 25.412. Applications and completion records are on file at the AOGCC. 20. Seawater is currently injected in the Pt. McIntyre waterflood. It is possible that produced water will be used later in the project. Both water sources have previously been approved in Area Injection Order No. 4B. 21. Estimated average and maximum injection pressures (at pump discharge) for PMOP WAG wells are expected to be 4100 psi and 4500 psi respectively. 22. Surveillance and performance data for both water and gas injection in the PMOP indicates out of zone fractures have not occurred. 23. MI injection pressures are not likely to cause fracturing of the PMOP confining zones based on previous enhanced recovery injection performance. 24. Secondary recovery gas re-injection and pattern waterflood operations in the PMOP are projected to increase recovery to 42-45% of the original oil in place (OOIP). Conservation Order No. 3 �. April 19, 2000 page 3 25. The PMOP MI enhanced recovery project will increase oil recovery from the pool by 6% of the OOIP or by 32 MMSTB in the area where MI will be applied. CONCLUSIONS: Conservation Order No. 317A should be amended to allow implementation of an enhanced recovery project within the area defined as the Pt. McIntyre Pool. NGL required for the project will be manufactured from gas processed in the LPC. Implementation of a miscible gas injection project in the PMOP will significantly increase ultimate recovery, will not cause waste nor violate correlative rights. Surveillance activity associated with reservoir development, waterflood, and miscible injection operations reporting should be consolidated into one report documenting significant activity on an annual basis. The record for this order should include the hearing record and administrative files related to Conservation Order No. 317 and Conservation Order No. 317A, including approvals issued under those orders. 6. The PMOP miscible gas injection project and the WBOP injection project will not cause waste, jeopardize correlative rights, or impair ultimate recovery. NOW, THEREFORE, IT IS ORDERED THAT (1) Conservation Order No. 317B supersedes Conservation Order No. 317A dated April 25, 1996 and Conservation Order No. 317 dated July2, 1993. (2) The following rules, in addition to statewide requirements under 20 AAC 25, apply to the affected area described below: Umiat Meridian T12N R15E Section 18 All. Section 19 NI/2. T12N R14E Section 13 All. Section 14 All. Section 23 N1/2 NW1/4, N1/2 NEI/4, SWIA NW1/4. Section 24 NI/2. T12N R14E Section 15 All Section 16 All Section 21 N1/2 NE 1/4. Section 22 N1/2. T12N R14E Section 17 NEIA, N1/2, SE 1/4, E1/2 E1/2 NWI/4, EI/2 NEI/4 SWI/4. T12N R14E Section 3 All. Section 4 All. Section 9 All. Section 10 All. • Conservation Order No. 3 0 April 19, 2000 page 4 400 Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and 11, T12N, R14E, UM, AK (Identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, RI 5E, UM, AK (Identical with line 6-7 on Block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares. Rule 1 Plan of Development and Operation Regular production may not begin until the interests of the working interest and royalty owners are integrated in accordance with the provisions of 20 AAC 25.517, and the plan of development and operation has been approved by the Commission under the provisions of AS 31.05.030(d)(9). Rule 2 Field and Pool Names The field is the Pt. McIntyre oil field. Hydrocarbons contained within the Kuparuk River and Kalubik Formations constitute a single associated gas and oil reservoir called the Pt. McIntyre Oil Pool. Hydrocarbons contained within the Seabee formation constitute a single associated gas and oil reservoir called the Stump Island Oil Pool. Rule 3 Pool Definition The Pt. McIntyre oil pool is defined as the accumulation of hydrocarbons common to and which correlates with the interval from 9908 to 10665 foot measured depth in the ARCO Pt. McIntyre No. 11 well. The Stump Island oil pool is defined as the accumulation of hydrocarbons common to and which correlates with the interval from 8759 to 8930 foot measured depth in the ARCO Pt. McIntyre No. 3 well. Rule 4 Well Spacing 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 5 Casing and Cementing a. A conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe. Cement to surface shall be verified by visual inspection. The Commission may administratively waive or approve other conductor setting depths and sealing methods that are supported by sound engineering principles. b. Surface casing shall be set at least 500 feet MD below the base of the permafrost but not below 5000 feet TVDss. Sufficient cement shall be used to fill the annulus behind the casing to the surface; if Conservation Order No. 3 April 19, 2000 page 5 complete fill -up is not obtained, a top job will be performed before proceeding with drilling operations. c. Structural casing is not required. Rule 6 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 7 Drilling and Production Equipment Drilling and production equipment must meet the requirements of API RP 7G, Section 8, "Drillstem Corrosion and Sulfide Stress Cracking," current edition. Rule 8 Automatic Shut In Equipment a. Upon completion, each well which is capable of unassisted flow of hydrocarbons to the surface shall be equipped with: i. a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow. ii. a fail-safe automatic subsurface safety valve (SSSV), unless other types of subsurface valve are approved by the Commission, shall be installed in the tubing string below the base of the permafrost and be capable of preventing uncontrolled flow. b. A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have fail-safe automatic SSSV's. c. SSSV's may be temporarily removed as part of routine well operations without specific notice to, or authorization by the Commission. Rule 9 Wellbore Commingling a. Production from the Pt. McIntyre and Stump Island oil pools may be commingled in the wellbore of the Pt. McIntyre No. 3 well. i. Allocation to each pool may be determined by production profile surveys or separate zone well tests. ii. The Commission may require additional production surveillance methods and may administratively accept alternative methods of allocation of wellbore commingled production upon application by the operator. b. Additional wells may be approved administratively for wellbore commingling on a case-by-case basis upon application to the Commission. Conservation Order No. SO April 19, 2000 page 6 Rule 10 Surface Commingling and Common Facilities a. Production from the Pt. McIntyre and Stump Island oil pools 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 Commission monthly in both computer file and report formats. i. 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. 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 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. 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 11 Production Anomalies In the event of oil production capacity proration at or from the LPC, all commingled pools produced at the LPC will be prorated by an equivalent percentage of oil production recognizing mechanical limitations and operational constraints. Conservation Order No. 31 April 19, 2000 page 7 Rule 12 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 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. 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. Rule 13 Gas -Oil -Ratio Exemption Wells producing from the Pt. McIntyre and Stump Island oil pools are exempt from the gas -oil ratio limit set forth in 20 AAC 25.240(b) so long as the provisions of 20 AAC 25.240(c) apply. Rule 14 Administrative Action Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative rights, and is based on sound engineering principles. Rule 15 Pt. McIntyre Oil Pool Annual Reservoir Report An annual Pt. McIntyre 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 enhanced recovery project(s) implementation and 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. f. Future development plans. g. Review of Annual Plan of Operations and Development. Conservation Order No. 30 April 19, 2000 page 8 Rule 16 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 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. DONE at Anchorage, Alaska and dated April 19, 2000. 4obert N. tenson, P.E., Chair Alaska Oil and Gas Conservation Commission Camille Oechsli Taylor, Commissi6ner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may 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 (Le. 10th day after the application for rehearing was filed). • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: AN ORDER rescinding those rules within existing Conservation Orders relating to well safety valve systems. Docket Number: CO -10-21 Other Order No. 66 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: 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 diary 11, 201 Daniel T. Se ou' , r., Commissioner, Chair it s Conservation Commission 'III fl, Co ne or a OirmanCa as,Conservation Commission CatHy P. Ybersterr, Commissioner Alaska it and Gas Conservation Commission Other Order 66 • Statewide, AK January 11, 2011 RECONSIDERATION AND APPEAL NOTICE 0 Page 3 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 the date on which the Commission mails, OR 30 days if the Commission 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 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(b), "[tlhe 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. 0 0 Fisher, Samantha J (DOA) From: Fisher, Samantha J (DOA) Sent: Tuesday, January 11, 20114:08 PM To: Ballantine, Tab A (LAW); '(foms2@mtaonline. net)';'(michael.j.nelson @conocophillips. com)'; '(Von. L. Hutchins@conocophillips.com)'; 'AKDCWelllntegrityCoordinator'; '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 aarlington@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 O (DNR); 'Temple Davidson'; 'Teresa Imm'; 'Terrie Hubble'; 'Thor Cutler'; 'Tina Grovier'; 'Todd Durkee'; 'Tony Hopfinger'; 'trmjr1'; '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) gohn.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@aiaska.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) Oohn.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) aim.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 Scx taux� F4 --4- A i a ka, OL, a4 -L. C7a k Caww-4rvarU) ►v Cots ►ztimiow (907)793-1223 (907)276-7542 (frw) 0 0 Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston Street, Ste 200 5333 Westheimer, Suite 100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Hodgden Oil Company NRG Associates President 40818 th Street P.O. Box 1655 Golden, CO 80401-2433 Colorado Springs, CO 80901 Bernie Karl CIRI K&K Recycling Inc. Land Department P.O. Box 58055 P.O. Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Jill Schneider P.O. Box 69 US Geological Survey Barrow, AK 99723 4200 University Drive Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith P.O. Box 190083 P.O. Box 39309 Anchorage, AK 99519 Ninilchick, AK 99639 Kenai National Wildlife Refuge Penny Vadla Refuge Manager 399 West Riverview Avenue P.O. Box 2139 Soldotna, AK 99669-7714 Soldotna, AK 99669-2139 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 795 E. 94th Ct. Anchorage, AK 99515-4295 Gordon Severson 3201 Westmar Circle Anchorage, AK 99508-4336 James Gibbs P.O. Box 1597 Soldotna, AK 99669 Cliff Burglin 319 Charles Street Fairbanks, AK 99701 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Rule Rescind Rule? Existing Order Requirement 25.265(x); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve Order 1 25.265(h)(5) arrangement or (ii) a single check valve and a SSV. Asubsurface-controlled injection valve or readopted regulation SCSSV satisfies the requirements of a single check valve" 25.265(x); 25.2659(b); 25.265(d)(1); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve fail-safe auto SSV and SCSSV; injection wells (except disposal) require Colville River Unit Qannik 605 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(x); 25.265(b); 25.265(d)(1); "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(h)(5)arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." 25.265(a); 25.265(b); 25.265(d)(2)(F); fail-safe auto SSV and SCSSV; injection wells (except disposal) require Oooguruk Oooguruk - Nuigsut 597 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.26a(a); 25.265(b); 25.265(d)(2)(H); "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(h)(5)readopted arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or valve satisfies single check valve requirement; test every 6 months SCSSV satisfies the requirements of a single check valve." 25.265(a); 25.265(b); 25.265(d)(2)(H); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve fail-safe auto SSV and SCSSV; injection wells (except disposal) require Oooguruk Oooguruk - Kuparuk 596 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(x); 25.265(b); 25.265(d)(2)(H); "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(h)(5)readopted arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or valve satisfies single check valve requirement; test every 6 months Prudhoe Bay Unit Raven 570 5 yes fail-safe auto SSV and SCSSV; maintain list of wells w/ removed or 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a) N/A deactivated SVS; sign on wellhead 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) fail-safe auto SSV and SCSSV; injection wells (except disposal) require Colville River Unit Fiord 569 5 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) valve satisfies single check valve requirement; test every 6 months 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) fail-safe auto SSV and SCSSV; injection wells (except disposal) require Colville River Unit Nanuq - Kuparuk 563 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); "Injection wells (excluding disposal injectors) must be equipped with(i) a double check valve valve satisfies single check valve requirement; test every 6 months 25.265(h)(5) 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 SCSSV satisfies the requirements of a single check valve." fail-safe auto SSV and SCSSV; injection wells (except disposal) require Colville River Unit Nanuq 562 6 no (i) double check valve, or (ii) single check valve and SSV; injection 25.265(x); 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; 25.265(h)(5) above or below permafrost. Injection wells must be equipped with a double check valve valve satisfies single check valve requirement; test every 6 months Prudhoe Bay Unit Put River 559 3 yes fail-safe auto SSV; SSSV landing nipple below permafrost; test as 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 SCSSV satisfies the requirements of a single check valve." prescribed by Commission Deep Creek Unit Happy Valley 553 3 yes SSV or SSSV Prudhoe Bay Unit Orion 505B 3 yes fail-safe auto SSV; SSSV landing nipple below permafrost; test as 25.265(a); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a N/A prescribed by Commission Prudhoe Ba Unit Y Polaris 484A 3 yes fail-safe auto SSV; SSSV landing nipple below permafrost; test as prescribed by Commission Milne Point - fail-safe auto SSV; SSSV landing nipple below permafrost; gas/MI Milne Point Unit 477 5 yes injection well require SSSV or injection valve below permafrost; test Schrader Bluff every 6 months Prudhoe Bay Unit Borealis 471 3 yes fail-safe auto SSV; SSSV landing nipple below permafrost; gas/MI injection well require SSSV below permafrost; test every 6 months Northstar NOrthstar 458A 4 no fail-safe auto SSV and SCSSV; test as prescribed by Commission; 500 ft minimum setting depth for SSSV Prudhoe Ba Unit Y Aurora 4576 3 yes fail-safe auto SSV; SSSV landing nipple below permafrost; test every 6 months fail-safe auto SSV; gas/MI injectors require SSV and single check Kuparuk River Unit Meltwater 456A 5 no valve and SSSV landing nipple; water injection wells require (1) double check valve, or (ii) single check valve and SSV; test every 6 months Prudhoe Bay Unit Midnight Sun 452 6 yes fail-safe auto SSV (all injectors and producers capable of unassisted flow to surface); test every 6 months fail-safe auto SSV and SCSSV; SSSV may be installed above or below Duck Island Unit Eider 449 7 no permafrost; injection wells require double check valve; LIPS trip pressure; test every 6 months fail-safe auto SSV and SCSSV (producers and gas injectors); water Colville River Unit Alpine 443B 5 no injection wells require (i) double check valve, or (ii) single check valve and SSV fail-safe auto SSV; gas/MI injectors require SSV and single check Kuparuk River Unit Tabasco 435A 6 no valve and SSSV landing nipple; water injection wells require (i) double check valve, or (ii) single check valve and SSV; test every 6 months fail-safe auto SSV ISM well and artificial lift); sign on well 9 SVS Kuparuk River Unit; deactivated; maintain list of wells w/deactivated SVS; test as Kuparuk 432D 5 yes prescribed by Commission; CO 432D.009 modifies Rule 5(b) - LPP Milne Point Unit may be defeated on W. Sak injectors w/surface pressure <500psi w/ notice when defeated and placed back in service New Regulation Provisions Revised Rule - "Well safety valve systems" (2) Comment Addressing Re is from Order 25.265(x); 25.265(b); 25.265(d)(2)(H); "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(h)(5) arrangement or (ii) a single check valve and a SSV. Asubsurface-controlled injection valve or readopted regulation SCSSV satisfies the requirements of a single check valve" 25.265(x); 25.2659(b); 25.265(d)(1); "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(h)(5) arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or readopted regulation SCSSV satisfies the requirements of a single check valve." 25.265(x); 25.265(b); 25.265(d)(1); "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(h)(5)arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or readopted regulation SCSSV satisfies the requirements of a single check valve." 25.265(a); 25.265(b); 25.265(d)(2)(F); Requirement to maintain a wellhead sign and list of wells with 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned 25.26a(a); 25.265(b); 25.265(d)(2)(H); "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(h)(5)readopted arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or regulation SCSSV satisfies the requirements of a single check valve." 25.265(a); 25.265(b); 25.265(d)(2)(H); "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(h)(5)arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or readopted regulation SCSSV satisfies the requirements of a single check valve." 25.265(x); 25.265(b); 25.265(d)(2)(H); "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(h)(5)readopted arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or regulation SCSSV satisfies the requirements of a single check valve." 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a) N/A 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d)(1) "The minimum setting depth for a tubing conveyed subsurface safety valve is 500 feet." Existing pool rule established a minimum setting depth for the SSSV 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 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 25.265(h)(5) 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 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(x); 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; 25.265(h)(5) above or below permafrost. Injection wells must be equipped with a double check valve check valve requirements for injectors are not covered by arrangement" readopted regulation "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)(2)(H) arrangement or (ii) a single check valve and a SSV. A subsurface -controlled injection valve or readopted regulation SCSSV satisfies the requirements of a single check valve." 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 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) SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors Requirement to maintain a wellhead sign and list of wells with 25.265(a); 25.265(b); 25.265(h)(5); deactivated SVS was replaced with requirement to maintain a N/A tag on well when not manned; administrative approval CO 25.265(m) 432D.009 remains effective [re:defeating the LIPS when surface injection pressure for West Sak water injector is <500ps] Page 1 of 2 Orders Establishing Requirements for Well Safety Valve Systems 1/7/2011 Unit/Field Pool Conservation Order 1 Rule Rescind Rule? Existing Order Requirement Kuparuk River Unit Tarn 430A 6 no fail-safe auto SSV; gaslMI injectors require SSV and single check valve and SSSV landing nipple; water injection wells require (i) double SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors 25.265(a); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." check valve, or (ii) single check valve and SSV; test every 6 months Milne Point Unit Milne Point - Sag 423 7 no fail-safe auto SSV; injection wells require double check valve; test 25.265(x); 25.265(b); 25.265(d); River readopted regulation; readopted 25.265(d)(5) does not include 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be every 6 months defeated on West Sak water injectors with surface injection pressure less than 500psi " 4066.001 remains effective [re:defeating the LPS when surface fail-safe auto SSV; gas/MI injectors require SSV and single check 25.265(a); 25.265(b); 25.265(h); 25.265(m) N/A valve and SSSV landing nipple; water injection wells require (i) double Kuparuk River Unit Kuparuk -West Sak 4066 6 no check valve, or (ii) single check valve and SSV; test every 6 months; tag on well when not manned CO 4066.001 modifies Rule 6(e) - LPP may be defeated on W. Sak 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) injectors w/surface pressure <500psi w/ notice when defeated and 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5); 25.265(m) placed back in service 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.2650); 25.265(m) fail-safe auto SSV and SCSSV; LPS trip pressure; readily accessible Badami Badami 4028 6 yes control unit; SSSV below permafrost; NTE 210days between tests; 25.265(a); 25.265(b) N/A 25.265(a); 25.265(b); 25.265(h)(5); submit test results electronically within 14days; SVS defeated/removed 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a only if well SI or pad continuously manned Prudhoe Bay Unit North Prudhoe 345 4 yes fail-safe auto SSV (S/D well and artificial lift); sign on well if SVS deactivated; maintain list of wells w/deactivated SVS; test as 25.265(h); 25.265(n); 25.265(0) N/A AOGCC Policy - SVS Failures; issued by order of the Commission 3/30/1994 (signed by Commission Chairman prescribed by Commission fail-safe auto SSV (S/D well and artificial lift); if SSSV installed it must Prudhoe Bay Unit Prudhoe 341 E 5 yes be maintained and tested as part of SVS; sign on well if SVS deactivated; maintain list of wells w/deactivated SVS; test as prescribed by Commission Prudhoe Bay Unit Niakuk 329A 5 yes fail-safe auto SSV and SCSSV; maintain list of wells w/ removed or deactivated SVS; sign on wellhead Prudhoe Bay Unit Pt. McIntyre 317B 8 yes fail-safe auto SSV and SCSSV; SSSV may be rermoved as part of routine well ops w/o notice Prudhoe Bay Unit West Beach 311 B 6 yes fail-safe auto SSV; sign on well if SVS deactivated; maintain list of wells w/deactivated SVS; test as prescribed by Commission West Fork &east Fork (Sterling 300 5 yes fail-safe auto SVS on each production tubing Prudhoe Bay Unit Lisburne 207A 7 yes fail-safe auto SSV; sign on well if SVS deactivated; maintain list of wells w/deactivated SVS; test as prescribed by Commission Prudhoe Bay Unit Prudhoe - Kuparuk 98A 5 yes suitable automatic safety valve installed below base of permafrost to prevent uncontrolled flow Statewide N/A N/A N/A yes Commission policy dictating SVS performance testing requirements Footnotes (1) No SVS rules found in Injection Orders (2) New title for Revised Rule; "N/A" means entire pool rule to be rescinded New Regulation Provisions Re is from Order Revised Rule - "Well safetyvalves stems" �2 ) CommentAddressin 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 25.265(h)(5) 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 SCSSV satisfies the requirements of a single check valve." SSSV requirement for MI injectors 25.265(a); 25.265(b); 25.265(h)(5) "Injection wells must be equipped with a double check valve arrangement." Check valve requirements for injectors are not covered by readopted regulation "Injection wells (excluding disposal injectors) must be equipped 1 ( 9 Po l ) q pped double check valve Check valve requirements for injectors are not covered by 25.265(x); 25.265(b); 25.265(d); ce-c) t arrangement or (ii) a single check valve and a SSV. Asubsurface-controlled injection valve or readopted regulation; readopted 25.265(d)(5) does not include 25.265(h)(5) SCSSV satisfies the requirements of a single check valve. The Low Pressure Pilot may be SSSV requirement for MI injectors; administrative approval CO defeated on West Sak water injectors with surface injection pressure less than 500psi " 4066.001 remains effective [re:defeating the LPS when surface injection pressure for West Sak water injector is <500psi] 25.265(a); 25.265(b); 25.265(h); 25.265(m) N/A 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.2650); 25.265(m) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b); 25.265(d); N/A Readopted 25.265(d) dictates which wells require SSSV; 25.265(h)(5); 25.265(m) replaces SSSV nipple requirement for all wells 25.265(a); 25.265(b) N/A 25.265(a); 25.265(b); 25.265(h)(5); Requirement to maintain a wellhead sign and list of wells with 25.265(m) N/A deactivated SVS was replaced with requirement to maintain a tag on well when not manned 25.265(d) N/A Readopted 25.265(d) dictates which wells require SSSV; replaces SSSV nipple requirement for all wells 25.265(h); 25.265(n); 25.265(0) N/A AOGCC Policy - SVS Failures; issued by order of the Commission 3/30/1994 (signed by Commission Chairman Dave Johnson) Page 2 of 2 • • Public Hearing Record And Backup Information available in Other 66 �oALAI,a))KA FRANK H. MURKOWSKI, GOVERNOR �s[J•►7KA OIL � GAS 333 W. 7tl1 AVENUE, SUITE 100 CONSERVATIONCOMUSS`ION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 2767542 ADMINISTRATIVE APPROVAL NO 317B.001 Mr. Francis Sommer Prudhoe Bay Asset Manager BP Exploration (Alaska) Inc. P. 0. Box 196612 Anchorage, AK 99519-6612 Dear Mr. Sommer: By letter dated September 9, 2003, BP Exploration (Alaska), Inc. ("BPXA") requested authorization to commingle a portion of production from the Pt. McIntyre Oil Pool ("PMOP"), Drillsite PM2 with production from the Prudhoe Oil Pool and process the fluids within Prudhoe Bay Unit ("PBU") Initial Participating Area ("IPA"). This will require a change in Conservation Order 317B, Rule 10 concerning allocation of production, which currently allows commingling of PMOP production only at the Lisburne Production Center. The production will be diverted to the low-pressure system of Gathering Center 1 ("GC 1 "), greatly decreasing wellhead pressure. This has several effects: o Oil production from PMOP will increase due to less backpressure. o Gas and water constraints at the Lisburne Production Center ("LPC") will be reduced due to the diversion of fluids to GCI. o Additional water volumes flowing from PM2 to GC1 will be available for injection to other oil pools needing greater water injection volumes for reservoir performance. o PMOP producers that cannot currently flow will be brought on line, increasing reserves and improving the pattern conformance. Initially, BPXA proposed that NGLs processed at GC1 not be allocated back to the Pt. McIntyre reservoir. Rather, all gas produced into the GCI facilities would be treated as indigenous IPA natural gas. By letter dated October 16, 2003, the Department of Revenue ("DOR") proposed an alternative method of allocation of NGLs. By letter dated October 27, 2003, the Department of Natural Resources ("DNR) endorsed DOR's proposal. Per your letter of November 11, 2003 we understand that you agree with DOR's proposal. CO 317B.001 December 10, 2003 Page 2 of 3 The Commission finds that the proposed commingling of production from the PMOP with other PBU production will significantly increase ultimate recovery, will not promote waste or jeopardize correlative rights, and is based on sound engineering principles. Rule 10 is amended to read as follows: 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 ("GC1" ), 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. A minimum of two well tests per month will be performed on each well, when operational conditions allow. d. 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. e. 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 Commission. f. NGLs attributable to the PM2 to GC 1 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. g. 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. h. API gravity will be determined for each producing well annually by an API/MPMS approved method. i. Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. CO 317B.001 December 10, 2003 Page 3 of 3 Yearly allocation process reviews will be held with the Commission. The initial allocation review will be no later than July 1, 2004. DONE at Anchorage, Alaska and dated December 10, 2003. Sarah Palm Daniel T. Seamount, Jr. Chair Commissioner zffmE o ALASKA SARAH PALIN, GOVERNOR ALASKA OIL AND GABS 333 W 7th AVENUE, SUITE 100 CONSERVATION COMIISSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 ADMINISTRATIVE APPROVAL NO. 31713.002 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 15 Pt. McIntyre Oil Pool Annual Reservoir Report of Conservation Order 317B - Pt. McIntyre Oil Field, Pt. McIntyre Oil Pool, Stump Island 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 15 Pt. McIntyre Oil Pool Annual Reservoir Report is amended to read as follows (additions are in bold and [deletions are bracketed]): Rule 15 Pt. McIntyre Oil Pool Annual Reservoir Report An annual Pt. McIntyre 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 enhanced recovery project(s) implementation and 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. f. Future development plans. CO 317B.002 • May 23, 2007 Page 2 of 2 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. aka and dated May 23, 2007. IV ' Daniel T. Seamount, Jr. Commissioner zX -- Cathy . Foerster Com issioner Various Administrative Approvals for North So • 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@iogcc.state.ok.us>, Terrie Hubble <hubbletl@bp.com>, Sondra Stewman <StewmaSD@BP.com>, stanekj <stanekj@unocal.com>, trmjrl <trmjrl@aol.com>, jdarlington <jdarlington@forestoil.com>, nelson <knelson@petroleumnews.com>, Mark Dalton <mark.dalton@hdrinc.com>, Shannon Donnelly<shannon.donnelly@conocophillipscom>, "Mark P. Worcester" <mark.p.Worcester@conocophillips.corn>, Bob <bob@inletkeeper.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. Sommer" <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 <ddonkel@cfl.rr.com>, mckay <mckay@gci.net>, Barbara F Fullmer <barbara.Efullmer@conocophillips.com>, doug_schultze <doug_schultze@xtoenergy.com> Hank Alford <hank.alford@exxonmobil.com>, Mark Kovac <yesno I @gci.net>, gspfoff <gspfoff@aurorapower.com>, Gregg Nady <gregg.nady@shell.com>, Fred Steece <fred.steece@state.sd.us> rcrotty <rcrotty@ch2m.com>, jejones <jejones@aurorapower.com>, dapa <dapa@alaska.net> , eyancy <eyancy@seal-tite.net>, "James M. Ruud" <james.m.ruud@conocophillips.com>, Brit Lively <bl@mapalaska.com>, jah <j ah@dnr. state. ak.us>, buonoje <buonoje@bp.com>, Mark Hanley <mark_hanley@anadarko.com>, Julie Houle <julie_houle@dnr.state. ak.us>, John W Katz <jwkatz@alaskadc.org>, tablerk'<tablerk@unocal.com> Brady <brady@aoga.org>, Brian Havelock <beh@dnr.state.ak.us> Jim White <jimwhite@satx.rr.com>, "John S. Haworth" <john.s.haworth@exxonmobil.com>, marty <marty@rkindustrial.com>, ghammons <ghammons@aol.com>, rmclean <rmclean@pobox.alaska.net>, mkm7200 <mkm7200@aol.com>, Brian Gillespie<ifbmg@uaa.alaska.edu>, David L.Boelens <dboelens@aurorapower.com>, Todd Durkee <todd.durkee@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.eom>, 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_Kahn@fws.gov>, Jerry Dethlefs <Jerry.CDethlefs@conocophillips.com>, crockett@aoga.org, Tamera Sheffield <sheffield@aoga.org>, Jon Goltz <Jon. Goltz@conocophillips. com>, Roger Belman <roger.belman@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.state. ak.us>, Thomas E Maunder <tom_maunder@admin.state.ak.us>, :Stephen F Davies <steve_davies@admin. state.ak.us>, Keith Wiles <kwiles@marathonoil.com>, `Deanna Gamble <dgamble@kakivik.com>, James B Regg of 3 5/24/2007 6:40 AM Various Administrative Approvals for North Sib • <jim_regg@admin. state.ak.us>, Catherine P Foerster<cathy_foerster@admin.state.akus>, gregory micallef <micallef@clearwire.net>, Laura Silliphant <Laura_silliphant@dnr.state. ak.us>, David Steingreaber <david.esteingreaber@exxonmobil.corn>, akpratts@acsalaska.net, Robert Campbell <Robert. Campbell@reuters. com>, Steve Moothart <steve_moothart@dnr.state.ak.us>, Anna Raff <anna.raff@dowj ones. com>, Cliff Posey <cliff@posey.org>, , Meghan Powell <Meghan.Powell@asrcenergy.com>, Temple Davidson <temple_davidson@dnr.state.akus>, Walter Featherly<WFeatherly@PattonBoggs.com>, Tricia Waggoner <twaggoner@nrginc.com>, John Spain <jps@stateside.com>, Cody Rice <Cody_Rice@legis.state.ak.us>,;John Garing;<garingJD@bp.com>, Harry Engel <engelhr@bp.com>, Jim Winegarner<jimwinegarner@brooksrangepetro.com>, Matt Rader <matt_rader@dnr.state. ak.us>, carol smyth <carol. smyth@shell. com>, Arthur C Saltmarsh <art_saltmarsh@admin. state.ak.us>, Chris Gay <cdgay@marathonoil.com>, foms@mtaonline.net, Rudy Brueggeman<rudy.brueggemann@international.gc.ca>, Cary Carrigan <cary@kfgd.com>, Sonja Frankllin <sfranklin6@bloomberg.net>, Mike Bill <Michael'.Bill@bp.com>, Walter Quay <WQuay@chevron.com>, "Alan Birnbaum <\"\"Alan J Birnbaum \">" <alan_bimbaum\"@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 <j im_regg@admin. state. ak. us> Jody Colombie <jody colombie@admin. state. ak.us> Special Staff Assistant Alaska Oil and Gas Conservation Commission Department of Administration AI04E-22.pdf Content -Type: application/pdf Content -Encoding: base64 Content -Type: application/pdf C0311B-002.pdf Content -Encoding: base64 C0570-002.pdf Content -Type: application/pdf Content -Encoding: base64 C0471-006.pdf Content -Type: application/pdf Content -Encoding: base64 Content -Type: application/pdf C0484A-001.pdf Content -Encoding base64 2 of 3 5/24/2007 6:40 AM Various Administrative Approvals for North SOO 0 CO457B-002.pdf Content -Type: application/pdf' Content -Encoding: base64 Content -Type: application/pdf CO317B-002.pdf Content -Encoding: base64 3 of 3 5/24/2007 6:40 AM Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department Box 129 Barrow, AK 99723 vl Mary Jones David McCaleb Mona Dickens XTO Energy, Inc. IHS Energy Group Tesoro Refining and Marketing Co. Cartography GEPS Supply & Distribution 810 Houston Street, Ste 2000 5333 Westheimer, Ste 100 300 Concord Plaza Drive Ft. Worth, TX 76102-6298 Houston, TX 77056 San Antonio, TX 78216 George Vaught, Jr. Jerry Hodgden Richard Neahring PO Box 13557 Hodgden Oil Company NRG Associates Denver, CO 80201-3557 408 18th Street President Golden, CO 80401-2433 PO Box 1655 Colorado Springs, CO 80901 John Levorsen Michael Parks Mark Wedman 200 North 3rd Street, #1202 Marple's Business Newsletter Halliburton Boise, ID 83702 117 West Mercer St, Ste 200 6900 Arctic Blvd. Seattle, WA 98119-3960 Anchorage, AK 99502 Baker Oil Tools Schlumberger Ciri 4730 Business Park Blvd., #44 Drilling and Measurements Land Department Anchorage, AK 99503 2525 Gambell Street #400 PO Box 93330 Anchorage, AK 99503 Anchorage, AK 99503 Ivan Gillian Jill Schneider Gordon Severson 9649 Musket Bell Cr.#5 US Geological Survey 3201 Westmar Cr. Anchorage, AK 99507 4200 University Dr. Anchorage, AK 99508-4336 Anchorage, AK 99508 Jack Hakkila Darwin Waldsmith James Gibbs PO Box 190083 PO Box 39309 PO Box 1597 Anchorage, AK 99519 Ninilchick, AK 99639 Soldotna, AK 99669 Kenai National Wildlife Refuge Penny Vadla Richard Wagner Refuge Manager 399 West Riverview Avenue PO Box 60868 PO Box 2139 Soldotna, AK 99669-7714 Fairbanks, AK 99706 Soldotna, AK 99669-2139 Cliff Burglin Bernie Karl North Slope Borough PO Box 70131 K&K Recycling Inc. PO Box 69 Fairbanks, AK 99707 PO Box 58055 Barrow, AK 99723 Fairbanks, AK 99711 Williams Thomas Arctic Slope Regional Corporation Land Department Box 129 Barrow, AK 99723 vl Tlir STATE. °ALASKA GOVERNOR MICHAEL I. DUNLEAVY 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 Ms. Katrina Garner PBU Area Manager BP Exploration (Alaska) Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: CO -20-003 Alaska Oil and Gas Conservation Commission 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 311 B 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, 31 1B.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, 31 1B.003, 317B.003, 329B.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 207D.001, 311 B.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 151 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 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 8,900 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, 31713.003, 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 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 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 151h 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, 317B.003, 32913.005, 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 Soacine 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 GC 1 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, 311B.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 GC1 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 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 Pt. McIntyre 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 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, 31713.003, 32913.005, 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 Commingling 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. 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) 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 Monitoring 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 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. COs 207D.001, 31 1B.003, 317B.003, 329B.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 ComminElin¢ 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. I . 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, 31113.003, 31713.003, 32913.005, 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 Monitorine 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 1511 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 151h 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, 31 1B.003,317B.003, 329B.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 Soacine 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 Comminelina 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. i. 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, 31113.003, 317B.003, 329B.005, 345.002,362A.006, 570.010 April 3, 2020 Page 12 of 12 Rule 7: Reservoir Pressure Monitoring 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, 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. °",,,,"",,,=w Price Jeremy M. Price Chair, Commissioner Daniel T. oau.rrsu�.awwMnr. Seamount, Jr. mi�mioa`nvumwaroa Daniel T. Seamount, Jr. Commissioner AND APPEAL Jessie L. Chmielowski 13:ss:`si`o"eoo� 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 I'HE STATE 0fALASKA 1 IL GOVERNOR MIKL DUNLLAVY 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 Mr. Oliver Stemicki 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.00gcc.olaska.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, Hilcorp North Slope, LLC' (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. s The IA NOL for wells processed through the LPC is currently set at 2,500 prig. 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, 457B.006, 471.009, 484A.005,50513.003,559A.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 psig 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 Rules being replaced 207D Lisburne 15 457B Aurora 11 and 123 484A Polaris 11 505B Schrader Bluff 11 559A Put River 10 570 Raven 12 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, 311B.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 311B 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 11 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-OIA 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, 31 16.004, 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 4 of 4 f. 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, 1. "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 D51mY ned by JeleDate 10201 ODI M. Price 135g]9-0a'Do' Jeremy M. Price Chair, Commissioner Daniel T.Digitally signed by Wini xamoem,J,. Searnount, Jr. 11`'20101 o01 12 Deals -0e 00' Daniel T. Seamount, Jr Commissioner Digitally signed by Jessie L. Jessie L. Chmielowski Chmielowski 1`2020.10.01 ;2:12:07-09.00' 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 h 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 neat 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 16 J(ombie, Jody J (cED) From: Rixse, Melvin G (CED) Sent: Wednesday, June 10, 2020 2:27 PM To: Sternicki, Oliver R Cc: Colombie, Jody 1 (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 noturalflow, 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 area n unintended recipient of this a -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. Rixsepa Iask a govl. cc. Jody Colombie From: Colombie, Jody J (CED) Sent: Wednesday, June 10, 2020 8:59 AM To: Chmielowski, Jessie L C (CED) <jessie.chmielowskiPalaska eov> Cc: Rixse, Melvin G (CED) <melvin.rixsePalaska eov> 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(caalaska gov> Sent: Wednesday, June 10, 2020 8:57 AM To: Colombie, JodyJ (CED) <jody.colombieRaalaska ftov> Cc: Rixse, Melvin G (CED) <melvin.rixse @alaska Rov> 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 amble, 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 within 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 YY p)ubal rw16a ory�rJ,al3on Sr. Well Integrity Engineer BP Exploration Alaska Cell: 1 (907) 350 0759 oliver.stemicki(@bP.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 1 (CED) <jodv.colombieCcDalaska.gov> Sent: Friday, May 15, 2020 3:16 PM To: AOGCC_Public_Notices <AOGCC Public Notices @list state ak us> Subject: [AOGCC_Public_Notices] CO -20-008 Docket Number: CO -20-008 Prudhoe Bay Field, All Pools Jodv.L Colonbie Special Assistant Alaska Oil and Lias Conservation Commission 333 West 7h Avenue Anchorage, AK 99501 (907) 793-1221 Direct (907) 2 76- 7542 Far List Name: AOGCC Public NoticesCa list.state ak.us You subscribed as: rvan.danielPbp.com Unsubscribe at: http://list.state.ak.us/mailman/options/aogcc public notices/rvan.daniel*/`40bp.com STATE OF ALASKA ADVERTISINGNOTICE ORDER TO PUBLISHER SUBMITINVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED APFIDAVITOFPUBLTT� AGTDCOPYOF ADVERTISMENT ADVERTISING ORDER NUMBER 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 5/15/2020 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: (✓ LEGAL f- DISPLAY r CLASSIFIED f- OTHER (Specify below) i. DESCRIPTION PRICE CO-20-008 Initials of who prepared AO: Alaska Non -Taxable 92-600185 SUBMIT INVOICE SHOWING ADVERTTs"r ORDER NO., CERTIFIED AFFIDAVITOF PUBLICATION WI'rHATTACHED COPV OF ADVERnsMENr To: AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae 1 of I Total of All Pages $ REF Tye Number Amount Date Comments I PVN IVCO21795 z Ao AO-08-20-024 3 4 FIN AMOUNT SY Act. Template PGM LGR Object FY DIST LIQ 1 20 AOGCC 3046 20 2 3- 4 5 Purch n u ri Title: Pnrchming nn A Authority's Signature Telephone Number .O. a and receiving agency name must appear mall invoices and documents relating to this purchase. e stale is registered for tax free transactions under Chapter 32, IRScode. Registration number 92-73-0006 K. Items are for the exclusive use of the slate and of for resale. DISTRIBUTION: Division FircaVOriginal AO Copies: Publisher (taxed), 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 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. 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 7°i 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 am. 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 the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than June 20, 2020. Jeremy M. Price 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 14 n BP Exploration (Alaska) Inc. W�44p Attn: Well Integrity Coordinator, PRB-20. Post Office Box 196612tt . 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 EOA Gas Lift Pressure I.. 3/1L]J13 5/1/3.3 fi/}MIDIS B/9/ZOIS 9/EUW35 !!Ilt/ZOIS 1/6/.016 Figure 2 WOA Pad Gas Lift Header Pressure WOA Gas Lift Pressure. I,aoom 3/ll/M13 3/t/3035 6/}Ulm3 8/9/1013 9RbID13 11/ll/$ms 1/6/l.6 l/}yIDl6 Ogle B? Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561 -511 1 February 20, 2020 Via USPS and Electronic Delivery Jeremy Price Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7`s Avenue, Suite 100 Anchorage, AK 99501 0 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, 1Ob,d, IOg, IOh, IOi, l Oj, 12a -f, 16b; CO 329A Rules 3, 6b,d, f -j, 8a -f, e; CO 311B Rules 3, 7b, d, f -k; 9a -f; CO 345 Rules 5b,d,f-i, 7a -f; CO 362A.005 Rule 1; CO 570 (Corrected) Rule 3; AA No. 570.002; CO 570.004 Rule 6 b, d, f -i; , I 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 1 — March 31, BPXA RECEIVED FEB 21 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. • 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). • 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. • 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 There shall be no restrictions as to well spacing except that no fThe 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. 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.] �S =1129M. . t 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 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 15`h 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 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 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, 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 Soacine 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 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 [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 0 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. [1 Of) API gravity will be determined for each producing well annually by an API/MPMS approved method. I Og) Gas samples will be taken and analyzed for composition from each non -gas lifted producing well yearly. 10h) 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.] 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 forth 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 5 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 Project [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 thesamepool.] 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 Commingling 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. [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 F producing well yearly. j.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 10412, 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. f Results and data from any additional reservoir pressure tests, surveys or special monitoring techniques shall be submitted in accordance with part'e' ofthis 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 July 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 monitoring techniques tests or surveys shall also be submitted as prescribed in (b) of this rule West Beach Oil Pool Conservation Order 311B Rule 3 Well Spacin¢ There shall be no restrictions as to well spacing except that no nay 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 Commin lin¢ [(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. [(t) 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 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 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 1*1 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 he suhmitted to rhe AnOC in rnninnrtinn 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 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 gny special reservoir pressure monitoring techniques, 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 (sub paragraphs). (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. [(f) Water volumes will be determined by APUMPMS 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 APUMPMS 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. 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 avoroximate 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 pressuretime depths temperature and M 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 monitorintz 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. i.Quarterly 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 year. 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 administrative 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. If you have any questions regarding this request, please contact Bill Bredar at 564-5348 or through email at William.bredar@bp.com. Si�nJcerreely, �j / �+e-C/.civ� .+ 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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Nd env a Ymn -412 Prudhoe Bay Field - Annual Surveillance Reporting Requirements to AOGCC Amends Order/Rule Order Date Comment Group 1 IPA Group 2 GPMA Group 3 Satellites Annual Surveillance Report Annual Overview Presentation Production Period to be Covered C0341 D Rule 11 11/30/2001 Note C0341 E (modified Pool Definition to include a portion of Put River Sandstone) 15 -Mar 15 -Jun 15 -Sep Group 2 - GPMA Oil Pools 22 -Jun 22 -Sep CO207, 207A Rule 9 C0345 Rule 8 12/16/1994 No rule on Surveillance reports C0317B Rule 15 4/19/2000 Jan 1 -Dec 31 Apr 1 -Mar 31 Jul 1 -Jun 30 Amends Order/Rule Order Date Comment Group I - IPA Oil Pools Prudhoe Oil Pool Put River Oil Pool C0341 D Rule 11 11/30/2001 Note C0341 E (modified Pool Definition to include a portion of Put River Sandstone) C0559 11/22/2006 Corrected 2/14/2006 Group 2 - GPMA Oil Pools — --------- Lisburne Niakuk..--00329A ____,__North_Prudhoe Bay Pt. McIntyre Raven Oil Pool CO207, 207A Rule 9 C0345 Rule 8 12/16/1994 No rule on Surveillance reports C0317B Rule 15 4/19/2000 C0570 Rule 10 8/-9/2006 West Beach Oil Pool C031 I B Rule 13 8/1/2000 Group 3 - Prudhoe Satellite Oil Pools Aurora Boreallis Midnight Sun Orion Polaris, C-0457BRule 8 6/25/2004 (corrected EV9!2 C0471 Rule 4 C0452 Rule 11 11/15/2000 C0505A Rule 9 C0484A Rule 9 4/28/2006 11/3/2005 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 <dave_roby@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 <artsaltmarsh@admin.state.ak.us>, Thomas E Maunder <tom maunder@admin.state.ak.us> There is something I didn't get around to before I left 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 - IPA Oil Pools Prudhoe Oil Pool C0341D Put River Oil Pool C0559 Group 2 - GPMA Oil Pools Lisburne CO207, 207A Niakuk C0329A Rule 9 North Prudhoe Bay C0345 Pt. McIntyre C0317B Raven Oil Pool C0570 West Beach Oil Pool C0311 B 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 wiiiiarnson(ii,)admin.state. ak.us> Organization: State of Alaska To:Lenig, David C <David.Lenig;(),bp.com> References: <CBF4D 8 E92B 5 A7 04 79F64416 5 8 2 FU'A i 7CB81 AvOgbp 1 ancex005.bpi. ad.bo.com> Oops Lenig, David C wrote: Hi Jane, of 3 4/23/2007 9:50 AM From: Jane Williamson [ : , v :v R - Sent: Thursday, August 31, 2006 5:14 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? I 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 IPA GPMA Satellites Annual Surveillance Report March 15 June 15 September 15 Annual Overview Presentation March 22 June 22 September 22 Plan of Development March 30 June 30 September 30 Production Period Janl-Dec31 Aprl-Mar31 Jull-Jun30 -----Original Message ----- From: Jane Williamson [mailto:jane williamson@admin.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 2 of 3 4/23/2007 9:50 AM administrative action process. Thanks. Jane Senior Reservoir Engineer (907) 793-1226 Alaska Oil and Gas Conservation Commission surveillance report.gls Content -Type: application/vnd.ms-excel Content -Encoding: base64 3 of 3 4/23/2007 9:50 AM 411 DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS CERTIFIED MAIL RERURN RECEIPT REQUESTED January 27, 2004 Francis Sommer Prudhoe Bay Asset Manager, Greater Prudhoe Bay BP Exploration (Alaska), Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 K MURKOWSKI, GOVERNOR 550 WEST 7' AVENUE, SUITE 800 ANCHORAGE, ALASKA 99501-3560 PHONE: (907) 269-8800 FAX (907) 269-8938 _^ — 'N -7AVEJ JV 2 8 2004 Alaska Cil &Gas Cons. Commiss" Anchorage Re: Revised Request to Commingle Pt. McIntyre Participating Area Production with IPA Production and Amendments to the Greater Pt. McIntyre Area Production Allocation Procedures Dear Mr. Sommer: By a letter dated September 9, 2003, BP Exploration (Alaska) Inc. (BPXA), as Prudhoe Bay Unit (PBU) Operator, submitted a request for authorization to commingle Prudhoe Bay Unit (PBU) Pt. McIntyre Participating Area (PMPA) production from the PM2 drillsite with production from the PBU Initial Participating Areas (IPA) through surface facilities at Gathering Center 1 (GC -1). The Department of Revenue Tax Division (DOR) and the Division of Oil and Gas (Division) responded to BPXA's request by letters dated October 16 and 27, 2003, respectively. DOR objected to treating the NGLs recovered from the PM2 to GCl gas stream as IPA fluids and proposed a simplified method of allocating those NGLs to the PMPA. Its proposal was to take the percentage of total separator off -gas that is attributable to PMPA wells producing into GCI, with the gas lift gas netted out, multiplied by the total NGL recovery at the CGF. The Division expressed the same concerns and proposed a similar methodology, but with the PMPA separator off -gas debited for fuel and flare uses at GC 1 in addition to netting out the gas lift gas component. Both agencies supported treating PMPA gas, other than that gas turned into NGLs, as indigenous IPA natural gas. In response to the agency letters, BPXA, on November 11, 2003, amended its original request to commingle PBU and PMPA production to use the simplified NGL allocation method proposed by the DOR. It also requested approval to change production allocation within the Greater Pt. McIntyre Area (GPMA) to a rate table allocation methodology, and provided additional clarification regarding the allocation procedures for PMPA production. The November 11, 2003, letter sets forth the details of BPXA's revised proposal on these issues. "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans." ti Mr. Francis Sommer PM2 to GC -1 Project and GPMA Allocation Procedures January 27, 2004 Page 2 Based on our review of BPXA's revised request, meetings with BPXA regarding the PBU Western Satellite Production Metering Plan (WSPMP) and the proposed modifications to the Plan, and conversations with the DOR and the Alaska Oil and Gas Conservation Commission, which has already approved the commingling request in Administrative Approval No. 317.001, the Division issues the following decision on BPXA's revised request. (1) The Division approves BPXA's request to commingle PMPA production with IPA production using the simplified NGL allocation method proposed by the DOR, subject to the following conditions: (a) BPXA shall submit to the Division, within five working days of their execution, any amendments to the Special, Supplemental Provisions to the PBU Operating Agreement for the PMPA, or the Pt. McIntyre Facility Sharing Agreement (collectively referred to as the Agreements) authorizing the use of IPA production equipment and services for Pt. McIntyre operations. If the PBU Owners decide against amending these Agreements as a result of either the PM2 to GC Project or the "Waterwheel" Project, BPXA shall notify the Division in writing about the decision within five working days of making it; and (b) BPXA shall submit the final list of wells whose production BPXA will send to GC -1 from PM2. Subject to the foregoing, any PMPA gas sent to GC -1, other than that gas turned into NGLs, may be treated as indigenous IPA natural gas. (2) The Division approves BPXA's request to change the allocation procedures for all the participating areas within GPMA from the currently approved well test methodology to the rate table methodology outlined on page three of BPXA's November 11, 2003, letter. The following sections of the Division's Findings and Decisions regarding GPMA participating areas are amended to refer to the rate table methodology: (a) Findings and Condition #12 of the Decision and Findings of the Director of the Division of Oil and Gas regarding the Amended Application for the Third Expansion of the Unit Area and Formation of the Pt. McIntyre Participating Area, dated December 30, 1993; (b) Section VI. 9. of the Decision and Findings of the Commissioner Alaska Department of Natural Resources regarding the Application for the Formation of the West Beach Participating Area, dated April 4, 1993; (c) Section VI. S. of the Decision and Findings of the Commissioner Alaska Department of Natural Resources regarding the Application for the Formation of the North Prudhoe Bay Participating Area, dated December 30, 1994; (d) Section VI. 7. of the Decision and Findings of the Commissioner Alaska Department of Natural Resources regarding the Application for the Formation of the Niakuk Participating Area, dated March 2, 1994; and (e) Section VI. 10. of the Decision and Findings of the Commissioner Alaska Department of Natural Resources regarding the Application for the Fourth Expansion of the Unit Area, First Expansion of the Niakuk Participating Area and Formation of the West Niakuk Participating Area dated November 17, 1997: Mr. Francis Sommer PM2 to GC -1 Project and GPMA Allocation Procedures January 27, 2004 Page 3 A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040(c) and (d) and may be mailed or delivered to Tom Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269- 8918, or sent by electronic mail to dnr_appeals@dnr.state.ak.us. This decision takes effect immediately. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Sincerely, Mark D. Myers Director cc: Commissioners, AOGCC Greg Bidwell, DOR Ken Rupp, BPXA Leslie Senden, BPXA 410 November 11, 2003 0 0 0 BP Exploration (Alaska) Inc. . 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-5111 Dr. Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West 7h Avenue, Suite 800 Anchorage, AK 99501 Ms. Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 West 7`h Ave, Suite 100 Anchorage, AK 99501 Re: Revised Request to Commingle Prudhoe Bay Unit (PBU) and Pt. McIntyre Participating Area (PMPA) Production Dear Chair Palin and Dr. Myers: The intent of this letter is fourfold: 1) to respond to the Division of Oil and Gas letter, dated October 27, 2003, that rejected our initial request to commingle PBU and PMPA production and treat all gas from the PM2 to GC 1 stream as IPA gas, 2) to revise our original request to commingle PBU and PMPA production, 3) to request approval to change GPMA to rate table allocation methodology, and 4) to provide additional clarification regarding the allocation procedures for Pt. McIntyre production. BPXA, as operator of the Pt. McIntyre Participating Area (PMPA) within the Prudhoe Bay Unit, has received both the Department of Revenue Tax Division (DOR) letter dated October 16, 2003 and the Division of Oil and Gas letter dated October 27, 2003 regarding our previous request to commingle PBU and PMPA production, dated September 9, 2003. The DOR letter presented its objection to treating the NGLs recovered from the PM2 to GCl gas stream as IPA fluids and proposed a simplified method of allocating those NGLs to Pt. McIntyre. The proposed method consisted of taking the percentage of total separator off -gas that is attributable to Pt. McIntyre wells producing into GCI, with the gas lift gas netted out (gas lift gas from GPMA does not contain NGLs), multiplied by the total NGL recovery at the CGF. The DOG letter echoed the same concerns and proposed a similar methodology, but with the Pt. McIntyre separator off -gas debited for fuel and flare uses at GCI in addition to netting out the gas lift gas component. Both agencies supported our request to treat all injected gas as indigenous to the IPA. The PBU Working Interest Owners appreciate the DOG's allowance for fuel and flare uses and the recognition of the fact that we are not required to pay tax and royalty on produced gas used Page 1 of 4 for fuel and flare. However, while we would benefit from this change, the benefits do not warrant the cost and complexity of accounting for fuel gas and flare. Ignoring the fuel and flare factor is also consistent with the fact that the allocation of Pt. McIntyre NGLs is itself purposely simplified. A precise measure of the NGLs attributable to Pt. McIntyre gas would require costly and time-consuming process simulations on an ongoing basis. We therefore prefer to keep the NGL allocation as simple and streamlined as possible and are revising our original request to employ the simplified NGL allocation scheme proposed by the DOR. With this change in NGL allocations, we must now also revise our original request to commingle PBU and PMPA production on the surface at GC 1 and respectfully suggest the following change to Rule 10 of AOGCC Conservation Order 31713: a. Production from the Pt. McIntyre and Stump Island oil pools may be commingled on the surface with production from other pools for processing at the LPC and GCI prior to custody transfer. b. Production from each well will be determined by the rate table methodology set forth in the WSPMP. Allocation data and well test data will be supplied to the Commission monthly in both computer file and report formats. c. NGLs recovered 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 Commission. 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 attributable to Pt. McIntyre wells producing into GCL The Pt. McIntyre separator off -gas will be determined according to Section 10 b. above, and will not include the metered Pt. McIntyre gas lift gas supplied to wells flowing to GCL 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. We believe that the changes to Rule 10 can be handled administratively if DOG and DOR are in agreement with the simplified approach. The "Request to Commingle Production from the PMPA with IPA Production" submitted to your agencies on September 9, 2003 stated that "production from PMPA wells that is commingled with IPA production at GC 1 will be determined and allocated in accordance with the PBU Western Satellite Production Metering Plan' (WSPMP). To more clearly establish how we propose allocating PMPA production flowing to either the LPC or GC 1, we are providing the following description of our proposal as it applies to each "Key Provision' of the WSPMP. Page 2 of 4 1&2) The EOA allocation technique will be used for all GPMA wells (gas lifted and flowing) in place of the current well test allocation procedure. 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. This is a modification of the WSPMP, which uses the WOA allocation technique for flowing wells and the EOA allocation technique for gas lifted wells. 3) A minimum of two well tests per month will be performed on each GPMA well, when operational conditions allow. This is a modification of the WSPMP, which calls for one test per month per well. 4) All PM2 wells flowing exclusively to Gathering Center I (GCI) will use GCI's well allocation factor for oil, gas, and water. All PM2 wells flowing exclusively to the Lisburne Production Center (LPC) will use LPC's well allocation factor for oil, gas, and water. PM2 wells that flow to both GCI and LPC in the same month will use a prorated (GCI and LPC) well allocation factor for oil, gas, and water. 5) Within the GPMA, test separators will continue to have Micromotion meters for mass flow measurement and Phase Dynamics meters for water cut measurements. 6) Zero -rate tests will be performed at PM2 once a quarter (every three months). If leak rates are not within acceptable tolerances, corrective measures will be taken. Leak rates from the zero -rate test will be used to correct test rates as necessary. This procedure is consistent with the WSPMP. 7) Reservoir specific shrinkage factors will be used to correct metered fluids to stock tank barrels. This is consistent with both our current operations and the WSPMP. We also hereby request approval to change the allocation procedures for all participating areas within GPMA from the current well test methodology that was approved in the decisions and findings for the PMPA to the rate table methodology outlined above. In accordance with the testimony provided in support of the WSPMP, allocation through the use of rate tables is expected to provide a more consistent, accurate, and efficient determination of fluid flow. Changing to the rate table methodology is included in the work scope to upgrade the GPMA automation system from Setcim to IP21. Work on this upgrade is in progress and is expected to be completed during 1Q 2004. Until completion, we will continue to allocate production according to the current well test methodology. To assist the agencies in evaluating the allocation procedures related to the PM2-GCI project, we have attached a summary of the overall project benefits. Also attached is the current expected well lineup for the PM2 wells. This chart shows where (GCI or LPC) each well will be Page 3 of 4 capable of flowing. Please note that this is preliminary and the final well lineup may change based on operational considerations. Please let me know if you need any clarification of this information. Respectfully, Francis Sommer Prudhoe Bay Asset Manager Greater Prudhoe Bay BP Exploration (Alaska) Inc. cc: Mr. Dan Kruse, ConocoPhillips Alaska, Inc. Mr. Marc Vela, ExxonMobil Mr. Dan Dickinson, Department of Revenue, Tax Division Mr. Mike Kotowski, Division of Oil and Gas Ms. Jane Williamson, Alaska Oil and Gas Conservation Commission Page 4 of 4 • 0 PM2 to GC1 Project Supplemental Project Information PM -2 to GC -1 Proiect Benefits This project is estimated to increase recoveries by 20-25 MMBO. The primary benefits are from debottlenecking production at Pt. McIntyre, improved efficiency of the Pt McIntyre base EOR and Supplemental MI projects and the supply of water to support waterflood operations in the GC -2 area. Waterflood (WF) Benefit Upgrading GC -1 to handle production from PM2 debottlenecks the Pt. McIntyre water production constraint that exists today at the Lisburne Production Center (LPC). This allows PM high water cut wells that are currently shut-in due to LPC facility constraints to be brought back on production and to stay on production longer. Low Permeability (kh) Production Benefit The low kh production benefit results from low kh PM2 wells, which cannot produce into the high pressure LPC system being able to produce into the lower pressure GC -1 system. EOR Response Benefit In addition to the waterflood benefit, increased enhanced oil recovery from MI injection will be realized from Pt McIntyre producers staying on production longer. This helps to maintain the integrity of the 9 -spot patterns and improves areal conformance of the WAG flood. MI Recovery Benefit Directing part of PM2 production to GC 1 will result in a higher amount of MI being recovered for use in enhanced oil recovery. The miscible injectant process at the CGF is more efficient than the recovery process at the Lisburne Production Center, with more return MI captured at the CGF than would occur at the LPC. Gas Constraint Benefits PM -2 to GC -1 project debottlenecks gas production as well as water production. Because Pt McIntyre is gas rate constrained, returned MI (RMI) entering the system from ongoing EOR operations would otherwise impact high GOR oil production. Producing a portion of PM2 to GC 1 reduces the impact since the marginal GOR at GC 1 are higher than at the LPC. GC -2 Water Benefit There is a need for additional injection water at GC -2 with the start-up of water injection projects in the Satellites and EWE. PM2 to GCI will facilitate meeting this demand by allowing PM water recovered at GC1 to be directed to the GC2 area via the recently connected GC1 — GC2 water tie -line. Based on water forecasts, the additional water from PM -2 wells producing into GC -1 should meet most of the anticipated demand. . �t PM2 to GC1 Projec Initial Well Lineup Well # Service After Startup LP&HP 1 HP Only (2) Infector NIS 3 LP Conversion (4) 1 LP&HP X 2 NIS X 3 LP&HP X 4 LP&HP X 5 NIS X 6 LP&HP X 7 LP&HP X 8 LP&HP X 9 Injector X 10 HP Only X High 11 LP&HP X 12 LP&HP X 13 LP&HP X 14 HP Only X High 15 Injector X 16 Injector X 17 LP&HP X 18 LP&HP X 19 LP&HP X 20 LP&HP X 21 LP&HP X 22 LP&HP X 23 Injector X 24 LP&HP X 25 LP&HP X 26 NIS X 27 LP&HP X 28 Injector X 29 Injector X 30 LP&HP X 31 LP&HP X 32 LP&HP X 33 LP&HP X 34 Injector X 35 LP&HP X 36 LP&H P X 37 LP&HP X 38 NIS X 39 NIS X 40 LP&HP X 41 LP&HP X 42 Injector X 43 NIS X 44 LP&HP X 45 HP Only X Medium 46 Injector X September 22, 2003 ` PM2 toGC 1 Project � Initial Well Lineup Well # Service After Startup LP&HP 1 HP Only (2) Infector 47 Injector X 48 HP Only X 49 LP&HP X 50 HP Only X 51 LP&HP X 52 LP&HP X 53 HP Only X 54 LP&HP X 55 NIS 56 HP Only X 57 HP Only X 58 HP Only X 59 LP&H P X 60 LP&HP X 34 9 10 NIS (3) LP Conversion (4) Medium Medium Low X Low Low High 7 Notes: 1) LP&HP wells can flow to either LPC or GC1 2) HP Only wells can only flow to LPC 3) NIS are not in service 4) HP Only wells are being scheduled for connection to LP system ranked high, medium, low for implementation. Some high ranked wells may be available for LP service at startup. September 22, 2003 DEPARTMENT OF NATURAL RESOURCES DIVISION OF OIL AND GAS CERTIFIED MAIL RERURN RECEIPT REQUESTED October 27, 2003 Francis Sommer Prudhoe Bay Asset Manager, Greater Prudhoe Bay BP Exploration (Alaska), Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 FRANKH. MURKOWSKI, GOVERNOR 550 WEST 7TH AVENUE, SUITE 800 ANCHORAGE, ALASKA 99501-3560 PHONE. (907) 269-8800 FAX (907) 269-8936 ,I q Re: Request to Commingle Pt. McIntyre Participating Area Production with IPA Production Dear Mr. Sommer: I am responding to your September 9, 2003 request for authorization to commingle Prudhoe Bay Unit (PBU) Pt. McIntyre Participating Area (PMPA) production from the PM2 drillsite with production from the PBU Initial Participating Areas (IPA) through surface facilities at Gathering Center 1 (GC - 1). The letter states, in part, that NGLs removed from PM2 gas produced through GC -1 facilities will be accounted for and reported as IPA fluids and any gas produced into GC -1 facilities from PMPA wells will be deemed "lost or consumed in operations" and any PMPA gas injected into the Prudhoe Bay Reservoir will be treated as indigenous IPA natural gas. After review of the supplemental materials submitted in support of this request and further analysis by staff, the Division of Oil and Gas (Division) is denying your request. The Division believes that NGLs removed from the production of PMPA wells through IPA facilities should be accounted for and reported as PMPA fluids, not IPA fluids. While we recognize the overall benefits of the PM2 to GC -1 Project, we disagree that commingling PMPA production with IPA production at GC -1 should transform PMPA fluids, whether oil or gas liquids, into IPA fluids. The Division also recognizes that a precise measure of the NGLs attributable to Pt. McIntyre gas would require costly and time-consuming process simulations on an ongoing basis. However, we agree with the Department of Revenue's view, as set out in its October 16, 2003 letter to you, that a simple formula can be used to approximate the quantity of Pt. McIntyre NGLs recovered at the Central Gas Facility (CGF). "Develop, Conserve, and Enhance Natural Resources for Present and Future Alaskans. " Mr. Francis Sommer PM2 to GC -1 Project October 27, 2003 Page 2 NGLs are recovered at the CGF from separator off -gas from the IPA, Prudhoe Bay satellites, or, after commingling, the PMPA. The gross amount of gas attributable to Pt. McIntyre wells*producing into GC -1 can be calculated using the current test separators at Pt. McIntyre. The PMPA apportioned share of fuel gas utilized in GC -1 and flare gas in any month can be based on its apportioned share of the total produced gas through GC -1. The Point McIntyre gas lift gas and the apportioned share of fuel and flare gas can be netted out to arrive at an estimate of the Pt. McIntyre gas that becomes separator off -gas at GC -1. After similarly accounting for gas lift and fuel and flare gas from the rest of the gathering centers and flow stations, the percentage of total PM 2 and IPA separator off -gas that is PM 2 Pt. McIntyre formation gas multiplied by total NGL recovery at the CGF provides a simple - to -calculate way of approximating NGL recovery from Pt. McIntyre production at the CGF. After taking into account the PMPA NGLs, the Division has no objection to treating Pt. McIntyre gas, other than that gas turned into NGLs, as indigenous IPA natural gas. A person affected by this decision may appeal it, in accordance with 11 AAC 02. Any appeal must be received within 20 calendar days after the date of "issuance" of this decision, as defined in 11 AAC 02.040(c) and (d) and may be mailed or delivered to Tom Irwin, Commissioner, Department of Natural Resources, 550 W. 7th Avenue, Suite 1400, Anchorage, Alaska 99501; faxed to 1-907-269- 8918, or sent by electronic mail to dnr_appeals@dnr.state.ak.us. This decision takes effect immediately. An eligible person must first appeal this decision in accordance with 11 AAC 02 before appealing this decision to Superior Court. A copy of 11 AAC 02 may be obtained from any regional information office of the Department of Natural Resources. Sincerely, _�Mark D. Myers P'-/Director cc: AOGCC Chair Greg Bidwell, ADOR Ken Rupp, BP Leslie Senden, BP Cm FRANK MURKOWSKI, GOVERNOR ❑ State Office Building PO Box 110420 Juneau, AK 99811-0420 907.465.2320 O 550 W Seventh, Suite 500 Anchorage, AK 99501-3566 907.269.6620 www.tax.state.ak.us October 16, 2003 Ms. Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Francis Sommer Prudhoe Bay Asset Manager BP Exploration (Alaska), Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 Re: BP Request to treat NGLs from Pt. McIntyre gas commingled with IPA Production as IPA NGLs Dear Chair Palin: In a letter dated September 9, 2003 entitled "Re: Request to Commingle Production from Pt. McIntyre Participating Area with IPA Production", BP's Francis Sommer proposes to account for and report NGLs removed from the production of Point McIntyre Participating Area wells as IPA fluids. The State Department of Revenue Tax Division believes that NGLs removed from the production of Point McIntyre Participating Area wells should be accounted for and reported as Point McIntyre fluids. While recognizing the benefits of commingling Point McIntyre production with IPA production at Prudhoe Bay Gathering Center 1, such commingling should not transform Point McIntyre fluids, whether oil or gas liquids, into IPA fluids. & 0 0 The Tax Division realizes that a precise measure of the NGLs attributable to Pt. McIntyre gas would require costly and time-consuming process simulations. However, a simple formula can be used to approximate the quantity of Pt. McIntyre NGLs recovered at the Central Gas Facility. NGLs are recovered at the CGF from separator off -gas from the IPA, or, after commingling, Prudhoe Bay satellites and the Point McIntyre PA. The amount of separator off -gas attributable to Pt. McIntyre wells producing into Gathering Center 1 can be calculated using the current test separators at Pt. McIntyre. The Point McIntyre gas lift gas (with its NGLs already stripped out) can be netted out to arrive at an estimate of the Pt. McIntyre formation gas that becomes separator off -gas. The percentage of total separator off -gas that is Pt. McIntyre formation gas multiplied by total NGL recovery at the CGF provides us with a simple -to -calculate way of approximating NGL recovery from Pt. McIntyre production at the CGF. At this time, the Tax Division has no objection to treating Pt. McIntyre gas other than that gas turned into NGLs as indigenous IPA natural gas. Respectfully, Dan ickinson, Director, Tax Division Department of Revenue Cc: Dr. Mark Myers, Director, Division of Oil and Gas Mr. Mike Kotowski, Division of Oil and Gas Ms. Jane Williamson, Alaska Oil and Gas Conservation Commission Mr. Dan Kruse, ConocoPhillips Alaska, Inc. Mr. Marc Vela, ExxonMobil --zaFlr- 7 September 9, 2003 Dr. Mark Myers, Director Division of Oil and Gas Department of Natural Resources 550 West 7th Avenue, Suite 800 Anchorage, Alaska 99501 BP Exploration(Alaska)Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907)561-5111 Ms. Sarah Palin, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, Alaska 99501 Re: Request to Commingle Production from Pt. McIntyre Participating Area with IPA Production Dear Chair Palin and Dr. Myers: BP Exploration (Alaska) Inc. (BPXA) as Operator of the Pt. McIntyre Participation Area (PMPA) within the Prudhoe Bay Unit (PBU), requests authorization to commingle a portion of the production from the Pt. McIntyre PM2 drillsite with production from the Initial Participating Areas (IPA) of the PBU through surface facilities at Gathering Center 1 (GC -1). This project will divert some of the Pt. McIntyre production from PM -2 drill site to GC -1, thereby reducing PM -2 wellhead pressure, increasing drawdown and utilizing water handling capacity at GC -1. The effects of gas and water constraints at the Lisburne Production Center (LPC) and hydraulic constraints in the production line to the LPC will be reduced. This debottlenecking greatly improves performance of the WAG process at Pt. McIntyre providing significant EOR benefits. The additional volumes of unprocessed fluids at GC -1 will result in increased produced water volumes, which will be transported through the GC -1 to GC -2 tie -line for use in Satellite development in the GC -2 area. Additional project details are included in Attachment 1. For royalty and tax purposes, production from PMPA wells that is commingled with IPA production at GC -1 will be treated in the same way as all other production from Prudhoe satellites that is processed in IPA production facilities. In particular, production from these wells will be determined and allocated in accordance with the PBU Western Satellite Production Metering Plan. The oil production so determined will be included in the Greater Pt. McIntyre Well Allocation Report. NGLs removed from the production of PMPA wells produced through GC -1 facilities will be accounted for and reported as IPA fluids and any gas produced into GC -1 facilities from PMPA wells will be deemed lost or consumed in operations, with the effect that all gas from all reservoirs separated at GC -1 that is injected into the Prudhoe Bay (Permo- Triassic) Reservoir will be treated as indigenous IPA natural gas for all purposes. Changes to Conservation Order 317B Rule 10, which governs the commingling of PMPA production into the LPC, will be required to address these changes. We've attached specific language changes to Conservation Order 317B, Rule 10 for the AOGCC's consideration (Attachment 2) for the commingling of PMPA fluids with IPA fluids as well as GPMA fluids. Please let me know if you need any more information to obtain approval for the changes requested. RespectfulI Francis Sommer Prudhoe Bay Asset Manager Greater Prudhoe Bay BP Exploration (Alaska) Inc. cc: Mr. Dan Kruse, ConocoPhillips Alaska, Inc. Mr. Marc Vela, ExxonMobil Mr. Dan Dickinson, Department of Revenue, Tax Division Mr. Mike Kotowski, Division of Oil and Gas Ms. Jane Williamson, Alaska Oil and Gas Conservation Commission 0 Attachment 1 • Application for Commingling of PMPA Production with IPA Production PM -2 to GC -1 Proiect Description The PM -2 to GC -1 project debottlenecks Pt. McIntyre's production by allowing some PM -2 drill site wells to be produced to GC -1. Pt. McIntyre's production is currently limited by gas and water capacity constraints at the Lisburne Production Center (LPC) as well as hydraulic constraints in the production line to the LPC. An existing out -of - service low pressure 36" Seawater Injection (SWI) pipeline will be used to route some of the PM -2 production to GC -1. With modifications, GC -1 will provide up to 90M BWPD of water handling capacity for the project and operates at a lower pressure than the LPC. This additional water capacity and lower pressure will improve the performance of the waterflood and Enhanced Oil Recovery (EOR) processes at Pt. McIntyre. The produced water resulting from processing of Pt. McIntyre fluids at GC -1 will be used to supply water for Satellite development in the GC -2 area through the GC -1 to GC -2 tie -line. Project start-up is expected to occur in late 2003. Incremental oil rate attributable to the project is expected to increase from approximately 4500 BOPD initially to a peak of more than 9000 BOPD as EOR response is realized. Proiect Scope Conversion of Seawater Injection Line The mothballed 36 inch Seawater Injection Line will be converted to move production from Pt. McIntyre drill site PM -2 to GC -1. PM -2 Manifoldine Header modifications will be required at PM -2. The existing production header will be utilized as a Low Pressure (LP) header for routing production to GC -1, and the existing Water Injection (WI) header will be utilized as a High Pressure (HP) header to accommodate production flow to the LPC. A new WI header will be installed for injection wells, thus minimizing the number of well tie-ins and manifold modules wall penetrations. Most PM -2 production wells will have the capability to flow to GC -1. However, only select wells will be able to flow to the LPC. Under the current design, only those wells capable of flowing into the higher -pressure system will be tied into the LPC header. PM -2 production is expected to be ramped up to match the GC -1 water handling capacity. A return line from the existing test separators will be added to allow for wells flowing to GC -1 to be tested at flowing pressure. New ESD/Pig Launcher Module The LP header will be routed to a new ESD/Pig Launcher module. The new module will contain three 24" ESD valves, a chemical skid and tankage for corrosion inhibitor, a hydraulic skid for valve actuation, and a 36" pig launcher. Two full port ball valves will be installed downstream of the new pig launcher to provide double block and bleed capability. � Attachment 1 i Application for Commingling of PMPA Production with IPA Production 36" Pining New 36" pipe will be installed on new VSMs from the new pig launcher to the tie-in point with the 36" SWI pipeline buried in the causeway. The segment of line coming from the STP will be abandoned in place with a blind and bleed. The tie-in to the existing 36" line will be made at the north West Dock breach to minimize traffic interruption. The following is a depiction of the major components at PM -2: STP PM2 Facility Changes 36" Jumper To GC1 Figure 1 IN sol ds Additions in red Cross Country 36" Pipeline An evaluation was made of the functionality of the 36 inch cross-country pipeline under expected flow rates, fluid temperatures and corrosion conditions. This evaluation resulted in the determination that the pipeline is suitable for the intended change in service. As a result, no work is planned for the cross-country pipeline as part of this project. GC -1 Modifications Use of the 36 -inch pipeline as a low velocity flowline is expected to cause larger than normal liquid slugs to the GC -1 Slug Catchers. To assist in mitigating the new slug impacts, the project scope includes raised weirs on two of the GC -1 Slug Catchers to 2 • Attachment• 1 Application for Commingling of PMPA Production with IPA Production provide additional surge volume and throttling divert valves to allow adjustment of flow between Slug Catcher trains. To debottleneck water handling, the project scope also includes GC -1 piping and control valve modifications downstream of slug catchers, dehydrators and produced water injection pumps. Reservoir Analysis The primary reservoir benefits of the project will result from the debottlenecking of production capacity limitations and improved efficiency and duration of the Pt McIntyre EOR flood. Many of the Pt McIntyre wells in the waterflood/EOR area are currently shut-in because of water handling constraints at the LPC. By moving some production to GC -1, it will be possible to return most of these shut-in wells to production (Figure 2). Reserve benefits at Pt McIntyre are therefore the result of enabling high water cut wells to stay on production longer, restoring the integrity of the 9 -spot patterns and improving areal conformance of the WAG flood. Also, low permeability wells that cannot produce into the high pressure LPC system can be produced into the lower pressure GC -1 system. Pt. McIntyre Field, Need for PM2 to GCI De -Bottlenecking Watertlood Patterns P2-22 P2.50A P2.14 P2.10 P2- p240 P2-13 P"- P246 ♦ P 2.18 P240 P2-336 AY %- A ♦ P1-01 P2.12 ♦ P2 2I P2 -SB P2•Ii %-27 P2-28 P1-23 pi P2d1 ♦ ♦ P2-10 %•11 P2 P2 -0B %-2f P2-18 P2-03 ♦ P2-25 Pt -21 P2-01 %-07 P2.29 P2.17♦ P2-20 ♦ P2d2 %-12 P1-1• P2 -3i Current MI Inje A +♦ pY P2P244Li P2.35 . Patterns 2 %-09 %. P2•M Pb11 %-20 %.17 PI -04 P2.52 %-07 • r • • N %-02A P2: P241 P2-38 ♦ • ♦,00• P1 ••� %48 %-05 P2.37 P2-53 %-25 �• -- Gravity D inage Area �, P2 -5/A ♦ P24M • • %"�+ %-02 �• • P2-506 • •••• ♦ ¢ •�... t••• P2.37 P2 -57A • Producer • • ♦ Injector ♦ Gas Cap Injector ¢Plugged and Abandoned 3 ction Attachment 2 Application for Commingling PMPA Production with IPA Production Proposed Modifications to CO 3176 • Modify Rule 10a to provide for commingling at GC -1: o "Production from the Pt. McIntyre and Stump Island oil pools may be commingled on the surface with production from other pools for processing at either the LPC or GC -1 prior to custody transfer." • Modify Rule 10b, iii and iv to recognize well allocations are to be done by processing facility: o "iii. Sum the TMP volume for all wells in all pools by processing facility (LPC or GC1)." o "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) for each processing facility." • Modify Rule 10c to recognize no allocation of NGLs for production sent to GC1: o " For production processed in the LPC only, 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." fl � ARCO Alaska, Inc. Post Office BJ*0360 0360 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 400 RE: Question Raised at the January 12-13 Hearing on Proposed Amendment to Area Injection Order No. 413. 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 4B. With respect to the Pt. McIntyre miscible Enhanced Oil Recovery (EOR) 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 EOR 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 Peck (SPE 59378) has been applied to tl- technique has indicated that the MMP could of approximately 300 psi. ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany estimating MMP developed by Wang and e Pt. McIntyre fluid characterization. This be as low as 4050 psi, resulting in a buffer oRiGi'llk!aL • 00 00 Please contact J. W. Groth (265-6846) or J. L. Hand (265-6036) if you have questions or require additional information. Sincerely, J. L. Hand cc: D. W. Bose (AAI) M. P. Evans (ExxonMobil) J. Hurliman (BPA) ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: POINT McINTYRE OIL POOL ENHANCED OIL RECOVERY PROJECT and WEST BEACH OIL POOL SECONDARY RECOVERY PROJECT APPLICATION FOR INJECTION AND AMENDMENT TO AREA INJECTION ORDER NO. 4B. APPEARANCES: Commissioners: TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska January 12, 2000 9:03 o'clock a.m. MS. CAMILLE OECHSLI MR. DAVE JOHNSTON METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5 6 15 16 17 18 19 20 21 22 23 24 25 P R O C E E D I N G S (On record 9:03 a.m.) COMMISSIONER OECHSLI: Good morning. It's about three minutes after 9:00 on January 12th. We're at the Commission Office at 3001 Porcupine Drive. This hearing was originally set for ARCO's application for injection and amendment to area injection order number 4B with respect to the Point McIntyre Oil Pool Enhanced Oil Recovery Project, and the West Beach Oil Pool Secondary Recovery Project. The notice was published on November 20, 1999, in the Anchorage Daily News for this hearing. Present at the head table: Dave Johnston, Cammy Oechsli. Present in the room are John Groth, Mark Worcester from ARCO, and Kristen Nelson from Petroleum News. Are we prepared to proceed? COMMISSIONER JOHNSTON: You've got to put on record what the purpose of the hearing is. COMMISSIONER OECHSLI: Purpose of the hearing was for the ARCO's application. COMMISSIONER JOHNSTON: Okay. Before we I proceed further, I would like to recuse myself from further deliberations in these matters. And the reason for that is that I have been advised by the Governor that I would not be reappointed to the Commission so I am now serving my last few days with this organization. Because of that, I think it would METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3� i 4� I 5� 6� 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 3 be inappropriate to be sitting in a decision-making matter concerning an affair of a company who I will probably be approaching for future employment opportunities. For that reason, I think there would be an ethical violation if I was to sit in judgment of a decision that is now pending before us. And for that reason, I feel it appropriate that I recuse myself from further deliberations in this matter. MR. GROTH: Well, we have no objection. COMMISSIONER OECHSLI: Is there anything further you would like to take up before we go off record? MR. GROTH: No, there's not. COMMISSIONER OECHSLI: Okay. With that, we'll go ahead and recess then until tomorrow morning at 9:00 o'clock. (Off record 9:07 a.m.) END OF PROCEEDINGS METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 COMMISSIONER OECHSLI: On Mr. Johnston's request, we no longer have a quorum since Mr. Christenson is not here. I apologize, Mr. Groth, and Mr. Worcester, for the inconvenience. If you have no objection, we could recess the hearing now and continue it to tomorrow morning at 9:00 o'clock. MR. GROTH: Well, we have no objection. COMMISSIONER OECHSLI: Is there anything further you would like to take up before we go off record? MR. GROTH: No, there's not. COMMISSIONER OECHSLI: Okay. With that, we'll go ahead and recess then until tomorrow morning at 9:00 o'clock. (Off record 9:07 a.m.) END OF PROCEEDINGS METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 C E R T I F I C A T E UNITED STATES OF AMERICA) ) ss. STATE OF ALASKA ) I, Laura Ferro, Notary Public in and for the State of Alaska, and Reporter for Metro Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Commission Public Hearing, was taken before me on the 12th day of January 2000, commencing at the hour of 9:03 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 3001 Porcupine Street, Anchorage, Alaska; That the hearing was transcribed by me to the best of my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 9th day of March 2000. Notary Public in and for Alaska My commission expires: 05/03/01 METRO COURT REPORTING, INC. 550 West Seventh Avenue. Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 00 00 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. 4B West Beach Testimony January 12, 2000 January 12, 2000 1 16 1� 00 00 Table of Contents SECTION A — TESTIMONY OF CARL E. LUNDGREN....................................................................... I SECTION B — TESTIMONY OF MICHAEL R. MORGAN................................................................... 3 West Beach Secondary Recovery Project Application - Testimony SII► � • � • 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. 1 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 -056, 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 00 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 tests 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 (SO4) associated with seawater breakthrough. However, the West Beach produced water stream will be inhibited upstream of the Pt. McIntyre/West Beach commingling point to prevent BaSO4 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 site L1 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 recovery can be justified. The existing 6" production line will be converted to a dedicated test line. To facilitate initiating production from the WB -05B 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 0• 00 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING January 12,2000 9:00 AM PtMcIntvre/WBeach NAME — AFFILIATION TELEPHONE Do you plan to testify? Yes No (PLEASE PRINT) yks v c, IVeLsd A 1' 2' 3 4 51 6'' 7' 8j 91I 10 11 12 13 14' 15 16' 17 18 19 20' 21' 22 23 24 25 *0 00 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING In Re: POINT McINTYRE OIL POOL ENHANCED OIL RECOVERY PROJECT and WEST BEACH OIL POOL SECONDARY RECOVERY PROJECT APPLICATION FOR INJECTION AND AMENDMENT TO AREA INJECTION ORDER NO. 4B. TRANSCRIPT OF PROCEEDINGS Anchorage, Alaska January 13, 2000 9:03 o'clock a.m. APPEARANCES: Commissioners: MR. ROBERT N. CHRISTENSON, CHAIRMAN MS. CAMILLE OECHSLI METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 ORIGINAL 2', 3� 4 5, 61 7 8'' 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 2511 • • P R O C E E D I N G S ME (On record 9:03 a.m.) CHAIRMAN CHRISTENSON: I would like to call this meeting to order. The purpose of the hearing is a request by ARCO on the Point McIntyre/West Beach Oil Pools for request authority to initiate miscible gas injection tertiary oil recovery. And it's about a little after 9:00. We are at 3001 Porcupine Road, and we will be reconvening the hearing that began yesterday. The Commission will receive both sworn and unsworn testimony. However, in our deliberations, we would like to notify you that you will -- we will give more credit to -- in our deliberations to sworn testimony. This will be recorded, and if you would like a transcription of these proceedings, please contact Metro Court Reporting Company. Persons wishing to testify need to sign in. And there's a list. Cammy's got the list or somebody's got the list here. COMMISSIONER OECHSLI: It's being passed around. CHAIRMAN CHRISTENSON: So please sign in. If you wish to give expert testimony, then please ask us about 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 a 10 11 12 13 14 15 16 17 1 18' rule on whether it will be admissible as expert witness. After the original presentation, we will accept testimony from those in the public who are present, and we will also accept written testimony. I think that's about it. Oh, the Notice was published in the Anchorage Daily News. I think that was the only paper that we did it in. So I think we are ready for the presentation of the testimony. So, ARCO, would you care to begin and be sworn in, if you so wish? MR. GROTH: Would -- my name is John Groth. Would you prefer to swear each of us in individually or..... CHAIRMAN CHRISTENSON: Yeah. MR. GROTH: .....collective? Okay. CHAIRMAN CHRISTENSON: Would you raise your right hand? (Oath administered) MR. GROTH: I do. 19!1 CHAIRMAN CHRISTENSON: Okay. Please be seated. 'I I 20,! MR. GROTH: Mr. Chairman, Commissioner, my name 2111 is John Groth. I am a supervisor with ARCO Alaska. I hold a �i 221!1' Bachelors of Science Degree in Chemical Engineering from Rice 231' University. I've been employed by ARCO since 1977 in a variety 241!1 of positions, and I've supervised the Greater Point McIntyre 2511 area development support effort since 1995. I would like to be METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 0 • • 4 recognized as an expert witness. CHAIRMAN CHRISTENSON: Okay. Do you have any questions? COMMISSIONER OECHSLI: I have no objection. CHAIRMAN CHRISTENSON: Okay. No objections. Please proceed. MR. GROTH: ARCO Alaska is presenting testimony' in support of the application to amend area injection order number 4, and the pool rules for the Point McIntyre__and West Beach fields. ARCO presents this testimony on behalf of the Point McIntyre working interest owners: ARCO, BP Amoco, and Exxon Corporation, and on behalf of the West Beach working interest owners, ARCO and Exxon. The testimony is divided into four parts. For the Point McIntyre EOR project, John Hand will describe the reservoir engineering aspects, and Murray Athans will describe the facility additions and modifications which are required. I For the West Beach water floor project, Carl Lundgren will describe the geologic aspects, and Mike Morgan will 1 describe the reservoir and facility aspects. Each witness is prepared to respond to questions II concerning his testimony and related exhibits. For the i convenience of the Commission, we have available the text of the testimony and copies of the exhibits. 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 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18' 19 22 23 24 25 • • 5 like to address. There are a number of exhibits -- number of I aspects of the West Beach portion of the application, exhibits, and testimony, we plan to give today that contain commercially sensitive confidential information. We believe that this information is useful background information for the Commission, but it's disclosure is not required for the public to understand or comment on the matter before us today. Those items are. In the application dated November 8, 1999, Exhibit F-1, Exhibit F-2; in the supplement dated December 16, 1999, Figures S-4, S-5, S-6, S-7, S-8, S-9; and with regard to today's testimony, the oral testimony of Carl Lundgren; and figures S-10, S-11, and S-12. And we request confidentiality of these items at this time. CHAIRMAN CHRISTENSON: I think before we get to the testimony, we can go into executive session, right? And listen to that. With respect to the items, you will submit these as confidential? MR. GROTH: The..... CHAIRMAN CHRISTENSON: .....items right now? MR. GROTH: Yes, we can. CHAIRMAN CHRISTENSON: Okay with you? COMMISSIONER OECHSLI: Yeah. (Off record comments) MR. GROTH: I think we've got a matter with BP folks as well on the West Beach items. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 (Off record comments) COMMISSIONER OECHSLI: Do you want to take a break? CHAIRMAN CHRISTENSON: Do you want to take a break to figure this out? Or we can start now. COMMISSIONER OECHSLI: Let me just ask a question. With respect to the order of information, were you going to do the Point McIntyre information all first and then do West Beach? !.No MR. GROTH: Yes. COMMISSIONER OECHSLI: Do any of these exhibits relate to that? They don't, do they? MR. GROTH: None of these exhibits that we just 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? that MR. GROTH: Yes, we are set up to do that. CHAIRMAN CHRISTENSON: Okay. Why don't we do 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 CHAIRMAN CHRISTENSON: Let's do Point Mac first. MR. GROTH: Unless there are any other I questions at this time..... CHAIRMAN CHRISTENSON: I don't have any. MR. GROTH: .....I'll turn the podium over to I John Hand. CHAIRMAN CHRISTENSON: Okay. COMMISSIONER OECHSLI: John, do you have copies of all those packages for us? MR. HAND: Here's the original testimony. CHAIRMAN CHRISTENSON: Do you wish to be sworn in? MR. HAND: Yes. CHAIRMAN CHRISTENSON: Please raise your right hand. (Oath administered) MR. HAND: Yes, I do. CHAIRMAN CHRISTENSON: Do you wish to be considered an expert witness? I MR. HAND: Yes, I do. I CHAIRMAN CHRISTENSON: Would you please tell us about your qualifications? MR. HAND: Mr. Chairman, members of the I Commission, ladies and gentlemen, my name is John L. Hand. I i METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 a. 1 2 3 • • a am the Subsurface Development Team Leader for the Point McIntyre Field. The Subsurface Development Team is a multi- company, multi -disciplinary team established by the owner 4'i companies. This team is responsible for the ongoing reservoir 5i management activities of the Point McIntyre Field. These 6'' activities include, but are not limited to, development 9 10 11 i 121 i 13 14 15 16 17 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 in 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, 181' Incorporated, as well as a number of field development planning 19'' assignments at ARCO Alaska, Incorporated. I worked in the 20 Greater Point McIntyre Area in my current position since 21' September of 1997. 22 I would like to be recognized as an expert witness. 23: CHAIRMAN CHRISTENSON: Do you have any 24 objections? 25.: COMMISSIONER OECHSLI: No, I don't. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 s 40 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • proceed. 0 CHAIRMAN CHRISTENSON: No objections. Please 91 MR. HAND: During my testimony today, I will provide information regarding current Point McIntyre field operations as well as the reservoir engineering aspects of the proposed Point McIntyre enhanced oil recovery project. Point McIntyre Pool startup occurred in October of 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 provided pressure support to the reservoir, maintaining an average reservoir pressure at the original pressure of approximately 4,370 psi. Source water, from the seawater treatment plant, is currently used for the Point McIntyre waterflood. Point McIntyre production is processed at the Lisburne Production Center, the LPC. Field oil production reached a facility -constrained plateau of 165,000 barrels of oil per day 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 Point McIntyre and water handling constraints at the LPC. To enhance recovery at oil -- of oil at Point McIntyre, METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 #s A • 9 10 1 the working interest owners, ARCO, BP Amoco, and Exxon 2 Corporation, have approved a hydrocarbon miscible EOR project. 3 Planned startup for MI injection is the first half of 2000. 4 Exhibit B-1 is a plat showing the location of all 5 existing injection wells, production wells, abandoned wells, 6 dry holes, and any other wells within the Point McIntyre Pool 7 as of June 1, 1999. The current Point McIntyre water and 8 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 PM1 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 I 18i number of 80 -acre infill wells and the extent of peripheral 19i 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, P1-25, is located at the West Dock 24 staging area. 25 All Point McIntyre water injection wells are completed METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 I i 1 & 0 1 2 6 7 8 9 10 11' 12 13 14 15 16 17 18 19 20 21 22 23 24 11 with L-80 grade steel. All tubing jewelry is completed with Chrome Moly, which is compatible with both L-80 and 13 Chrome. Point McIntyre water injection completions are designed as a single zone, single string with a single packer. Exhibits G-1 through G-5 show typical wellbore schematics for the five basic well completion designs. The current waterflood pattern configuration for the Point McIntyre Pool is an inverted nine -spot. This pattern selection provides maximum flexibility for potential future conversions to other pattern configurations, as well as in reservoir description and/or -- 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. Future development plans will be based on field performance, including the 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 EOR 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. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 12 The Point McIntyre EOR project involves the eventual conversion of the existing 15 waterflood injectors, and potentially any future water injectors to water -alternating - gas, or WAG, service. Water will be injected alternatively with MI in the WAG injection wells to improve the MI sweep in the reservoir. At startup of the EOR project, water injection is anticipated to be approximately 250,000 barrels of water a day. 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 Point 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 Point McIntyre reservoir under Area Injection Order 4B. Currently, injection of an MI slug of 35 percent of hydrocarbon pore volume 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 slug size and incremental oil recovery for the Point McIntyre Enhanced Oil Recovery Project. MI generated at the LPC is expected to be delivered to METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 A i ! I 2 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 13 Point McIntyre at a nominal 50 million standard cubic feet per day. Exhibit S-2 shows the predicted incremental oil production rates for the Point McIntyre Enhanced Oil Recovery Project for the next 23 years for the miscible gas injection rate of 50 million standard cubic feet per day. Exhibit S-3 shows the projected field oil production rates for the Point McIntyre base, primary and secondary, and a base plus EOR for the 50 million standard cubic foot case 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 EOR patterns mature, the availability of excess MI will allow additional patterns to begin receiving MI. Nominally, two patterns will be receiving MI at any one time during the life of the project. It will take around 15 plus years for the last pattern to receive its first MI slug. Peak incremental oil rate is expected to exceed 5,000 barrels per day as a result of the project. Current Point McIntyre operations, processed gas reinjection and pattern waterflooding, are expected to yield an estimated total recovery of approximately 42 to 45 percent original oil in place for the Point McIntyre Pool. The planned hydrocarbon miscible EOR project at Point McIntyre is estimated to increase oil recovery for an additional 32 million stock tank barrels of oil, or approximately six percent of the METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 11 2 3 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • 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 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 the field l' wide scale, with the estimated incremental oil recovery for the waterflood area determined using the Point McIntyre Full Field reservoir simulation model. MI for the Point McIntyre EOR project will be manufactured at the LPC from a mixture of produced fluids from the Point McIntyre, West Beach, North Prudhoe Bay, Nuyakuk, and Lisburne Pools. Based on the current operating practice of injecting processed natural gas from the LPC into Point 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 METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 11 2 I 3 4 5 6 7 8 9 10 11 12 13 14 15 16 1 I 17 I 18 I i 19 20 21 I 22 III 23 • • 15 enrichment level for the Point 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 4,350 psi. The expected composition is given in Exhibit H-1. Injection and production at the Point McIntyre field are managed to maintain the average reservoir pressure at the original reservoir pressure of approximately 4,370 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 Point McIntyre Oil Pool Annual Reservoir Report. The constant reservoir pressure with temperature along with ne- -- excuse me. 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 Point 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 degrees Fahrenheit. The thermal temperature bulb at Point McIntyre, due to source water injection, should METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 u 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. 5The projected potential maximum miscible injectant rate 6 under the current scope is 70 million standard cubic feet per 12 1 day. Expanding the Point McIntyre Enhanced Oil Recovery Project by increasing miscible gas injection rate beyond the current scope would require an external source of enriching components for the manufacturing the additional miscible injectant. This is a technically viable option and was part of the initial scoping studies for an EOR project at Point McIntyre. However, when this initial evaluation indicated less l 14' favorable economics 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 benefits of a miscible gas injection rate of up to 150 million 19 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 0 0 17 1 questions? 2 COMMISSIONER OECHSLI: I don't. 3 CHAIRMAN CHRISTENSON: I've got a couple of 4 questions. 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 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 221 processing capacity, water processing capacity and LPC, that's 231 holding you up as well? Or did I get that wrong? 24� MR. HAND: We talked about -- in the testimony I, 251 all I talked about was the expected water injection volumes at METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 0 18 the time of MI. CHAIRMAN CHRISTENSON: Okay. Well, somewhere I' thought I heard that there was a limitation on that..... MR. HAND: Oh, right. CHAIRMAN CHRISTENSON: .....processing capability. MR. HAND: Right. CHAIRMAN CHRISTENSON: MR. HAND: Right. CHAIRMAN CHRISTENSON: in this project? In LPC, right? Are you addressing that MR. HAND: I -- I feel that pro- -- I'm probably not the best person to answer that question. Maybe Murray Athans will be able to answer that when he talks about the facility -- facilities at Point McIntyre or the LPC in relation to this project. CHAIRMAN CHRISTENSON: Okay. So what you're going to do is in the initial phases, you're going to see how effective this MI is under the current project, and then you'll evaluate whether it would be advantageous to acquire additional MI for -- if it looks like that would be cost-effective. Is that correct? MR. HAND: That is correct. That is correct. CHAIRMAN CHRISTENSON: But any of that would have to come from another facility. Have I got that right? METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 • • "M■ MR. HAND: Yes. We would acquire an external source of miscible injectant or enriched hydrocarbon components to make miscible injectant. Yes. CHAIRMAN CHRISTENSON: Thanks. Anything else, Cammy? COMMISSIONER OECHSLI: I don't. CHAIRMAN CHRISTENSON: Thank you very much. MR. HAND: Thank you. MR. ATHANS: Good morning. My name is Murray Athans. CHAIRMAN CHRISTENSON: Would you like to be sworn in, sir? MR. ATHANS: Yes, I would. CHAIRMAN CHRISTENSON: Please raise your right hand. (Oath administered) MR. ATHANS: I do. CHAIRMAN CHRISTENSON: Do you wish to be considered an expert witness? MR. ATHANS: Yes, I do. CHAIRMAN CHRISTENSON: Would you present your qualifications, please? MR. ATHANS: Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Murray P. Athans. I am the ARCO Project Engineer for the Point McIntyre EOR METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 II 20 1 project. In this role, my job responsibilities have included 2I facility design, oversight and review, and acting as the I 3 1 primary coordinator between the engineering contractor and the 4) Lisburne Production Center, LPC, Operations Team. It has been 5my 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 Plano, Texas, in 1980, then transferred to ARCO Alaska in 1984. 141 Since arriving in Alaska, I have worked in a broad variety of i 151 facility planning and process engineering positions within the i 16'j Prudhoe Bay and Kuparuk business units. I transferred into the 17� Greater Point McIntyre Area in August 1997, at which time I l 181 began my current assignment as Project Engineer for the Point 1911 McIntyre EOR project. ii it 20!I would like to be recognized as an expert witness. iI 21I CHAIRMAN CHRISTENSON: Thank you. it 2211 COMMISSIONER OECHSLI: I have no objection. I 2311 CHAIRMAN CHRISTENSON: No objection. Please 24: proceed. 251, MR. ATHANS: Okay. During my testimony today, I METRO COURT REPORTING, INC. I 550 West Seventh Avenue, Suite 1 650 i Anchorage, Alaska 99501 (907) 276-3876 2 3� 4 5 I 6 7 8 9 10' 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • I will provide an overview of the facility modifications and additions which are being installed to implement the Point 21 McIntyre EOR project. I will also briefly discuss some of the project facility considerations that impacted the miscible injectant rate projections previously discussed by John Hand. Vapors generated in the LPC NGL, natural gas liquids, 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 LPC will not be impacted by the EOR project. 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 manufacturer rate is expected to be 50 million cubic feet per day. 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 four to five years of the project, MI rates during the summer are expected to range between 42 to 45 million cubic feet per day, while in the winter ranging between 52 to 53 million cubic feet per day. After four to five years, MI rates should be consistently in the 50 million cubic feet range, with peaks as high as 60 to 70 million cubic feet per day. Peak rates -- peak rate estimates are based in part on predictions of the METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 I 22 23 24 25 • • 22 1 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 capital. Modifications at the LPC during 1999 and early 2000 in support of the Point McIntyre EOR project include the installation of an MI compressor, a second chiller, new compressor coolers and blending station, and an upgrade of the LPC NGL plant liquid piping. MI will be transported to the Point Mac 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 I 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 H2S concentrations. we will continue to observe existing H2S safety precautions. The estimated maximum and average injection pressures anticipated for the Point McIntyre enhanced recovery projects METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5 6 7 8 9 10 11 16 17 18 19 20 21 22 23 24 25 0 23 are listed in the following table. These pressures represent pump discharge pressures. The estimated maximum injection rates for Point McIntyre 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. All field data collected to date indicate that injection in the current water injectors and the single gas injector at Point 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 Point 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. This concludes my testimony. CHAIRMAN CHRISTENSON: Cammy, do you have any questions? COMMISSIONER OECHSLI: I don't. CHAIRMAN CHRISTENSON: Could you answer the question with regard to the limit on the facilities? MR. ATHANS: Yes. Again, as I discuss in here, there are basically two primary factors that limit our MI rate 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 2 3� 4 i 5 6 7 8 9 10 11 I 12 1 13 1 19 20 21 22 23 24 25 • • 24 And, again, the first one is our metallurgical temperature limit on our piping. All of our piping is only rated by code down to minus 50 degrees Fahrenheit. So per code, we cannot go below minus 50 on the piping. You know, safety issue. And then secondly is we had some excess propane refrigeration capacity at the LPC already existing. And what we did with this project was we added a second chiller to basically, you know, use up that excess capacity so that we've sized that chiller such that it will efficiently use the rest of our capacity. And so basically those are the two things, our metallurgical temperature limit, and then now we are using up all the excess capacity. To go beyond that would have required very significant capital cost additions which we didn't judge to be economic. So those are the two primary factors that limit our rate. CHAIRMAN CHRISTENSON: Is there anything else that limits your rate? Is there a water handling problem? MR. ATHANS: No. Water handling really -- I mean that may limit our production rate but that really doesn't affect the MI rate. 1 CHAIRMAN CHRISTENSON: I know but does it I affect the rate of this EOR project? MR. ATHANS: No. No, because we're already -- METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 3' 41 I 5 6 7 8 9 10 11 12 13, 14 15 16 17 18 19 20 21 22 23 24 25 • • you know, we already have -- that really doesn't affect the amount of the MI components that we're going to be able to remove again. The temperature limits and the refrigeration limits are really what affect that, and water is really a separate issue. 25 MR. GROTH: May I? CHAIRMAN CHRISTENSON: Yeah, John. MR. GROTH: To the extent that, you know, water handling..... (Witness walks up to microphone) MR. GROTH: To the extent that the water handling capacity in and of itself has an effect upon the recovery for the EOR project, the answer would be limited. But to the extent the water handling capacity in and of itself has an impact on the ability of all of the fields within the Lisburne GPMA production system to produce, if you've got a higher water handling capacity within the plant, well, yes. There would be a higher through put rate associated with all the fields, and there would be instantaneous increases in production associated with that. CHAIRMAN CHRISTENSON: So it does have an overall effect then in -- I mean you could produce more if you had more water handling capacity? MR. GROTH: On an instantaneous basis, yes. MR. ATHANS: It starts to get pretty technical METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 3I 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • 26 though because if we're all -- I think what John is saying is we could produce more total gas if we could also produce more total oil but, again, it really begins to get complex then as to whether if we're already using all of our refrigeration capacity, those few extra components that we would bring in with the gas, you may or may not, depending on where you are in the life of the project, be able to capture those and efficiently use those. So it's not a, you know -- I don't think the affect is large at all. The fact that, you know, if we had a little more water handling capacity, I don't think you would see a tremendous increase in the MI rate. CHAIRMAN CHRISTENSON: Okay. Thanks. MR. GROTH: That does conclude our testimony for the Point McIntyre portion of the application. CHAIRMAN CHRISTENSON: Okay. Thank you. COMMISSIONER OECHSLI: Do you want to take a break at this point? CHAIRMAN CHRISTENSON: Yeah. Let's take a 10 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, we have one more question that came up in our discussions. It relates to the buffer between MMP and reservoir pressure. And 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 1 2 I 3i 4 5 6 i 7 8 9 10 11 12 13 14 15 16 17 18 19 0 • 27 some general parameter there how much that temperature is going to affect that buffer. You're talking about 20 psi between MMP and reservoir pressure. And then you also talked about how the temperature was going to give you a wider margin. We would like to hear your comments on what you think that's going to be, how much help you're going to get out of that? And our reasons are because we've heard a lot in other discussions with regard to that where you're looking at a 100 to 150 psi buffer. MR. HAND: The average reservoir pressure that we try and maintain the reservoir at, we talk about is a normal 4370. We take pressures every year and report that to the Commission, and other than the first eight months of production which we were not -- didn't have any water injection, we've actually probably normally kept it above that. And we monitor that pressure every year. We report that every year and monitor our pressure, with sag bottom hole pressures or flowing bottom hole pressures, right throughout the year. So it generally is a little higher than 4370 so that press- -- that type of pressure buffer is a little higher. 20ii 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'L pressure buffer. We -- I could -- at this point in time, I 241 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 required. CHAIRMAN CHRISTENSON: I don't think we're so much interested in a specific number as sort of a range. What do you expect to get in terms of overall benefit out of that? MR. HAND: You would..... CHAIRMAN CHRISTENSON: Because you said 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 i 11 of losing miscibility. It basically is essentially the same 12affect as increasing the pressure buffer that you have in the 13 field. So your miscibility will be met. You have less concern 14111 about losing miscibility. 151 CHAIRMAN CHRISTENSON: Yeah. Can you it 161, equivocate that to -- is that like going to be like a 50 psi i� 1711 buffer or a 100 psi buffer or what? MR. HAND: I really couldn't..... 19 j1 CHAIRMAN CHRISTENSON: We're not looking for 20! specific numbers here. 21 MR. HAND: Yeah. 22; CHAIRMAN CHRISTENSON: Just if you could give 23,11 us an idea so we would have some idea relative to other things 24 we know about. 251'1 MR. HAND: I really couldn't give you a METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • definite answer on that. I would have to get back to you on that one. CHAIRMAN CHRISTENSON: That's fine. MR. HAND: I will calculate that for you. CHAIRMAN CHRISTENSON: Okay. Do we have any other questions? 29 COMMISSIONER OECHSLI: No. CHAIRMAN CHRISTENSON: All right. John. MR. GROTH: May I -- one -- I guess a couple points of clarification on the water handling capacity question. I think we've got amongst ourselves a better understanding of what you were driving for there. The facility limits at the LPC are integrated and have implications upon each other. So you can have gas handling constraints. You can have water handling constraints. Within the GPMA system, there may be hydraulic constraints within certain common lines that feed into the LPC. We tend to look at that system as a whole. And in the past, water handling has been a constraint. Gas handling may have been a constraint. Oil processing capacity within the system has been a constraint. Those are things that we have looked at and will continue to look at to see if there are opportunities to de - bottleneck those. With the initiation of miscible injectant operations, that's another constraint that is now into the system but it will be integrated and will be part of our METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 i 21 22 23 24 25 4) 0 "MI ongoing evaluations to see if there are any opportunities to de -bottleneck the system as appropriate. CHAIRMAN CHRISTENSON: I noted that you said instantaneous value. So I guess the implication of that is that you don't expect -- even if you would find some things you wouldn't expect an increase in overall recovery. It just -- it's a timing situation whether you get it now or whether you get it later. MR. GROTH: I think there are elements of additional recovery that may come with a particular de- bottlenecking opportunity. But we look at both the instantaneous rate benefit and the additional recovery benefits associated with those to determine if that particular opportunity is economical. But the instantaneous rate benefit associated with those typically is a -- the larger portion of the benefits. CHAIRMAN CHRISTENSON: I think that clears it up for us. Let's see, at this time, is there any public testimony with regard to Greater Point Mac? We're going to try to split this up into the confidential and non -confidential issues. So we would like to wash out the Point Mac question. Are there any other testimonies or comments with regard to Point Mac? And then we'll move on to the confidential session. Seeing none, we need to go into confidential session. 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 • • need to -- besides Kristen. Are there others? Thank you, Kristen. 2884 (Meeting adjourned to go into executive session) 4415 31 1 (Public hearing reconvened) CHAIRMAN CHRISTENSON: Good morning. MR. MORGAN: Good morning. My name is Michael Morgan. I would like to be sworn in. CHAIRMAN CHRISTENSON: Okay, sir. Raise Your right hand. (Oath administered) MR. MORGAN: I do. CHAIRMAN CHRISTENSON: Do you wish to be considered an expert witness? MR. MORGAN: Yes, I do. CHAIRMAN CHRISTENSON: Okay. Would you proceed with your qualifications? MR. 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 i Colorado School of Mines in 1986. I have been employed by ARCO since 1986, and have worked a variety of engineering projects. 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 i ii 1 2 3 Pool development since February 1996. I would like to be recognized as an expert witness. CHAIRMAN CHRISTENSON: Cammy, do you have 4 any..... 5 ji 71 proceed. COMMISSIONER OECHSLI: No objection. CHAIRMAN CHRISTENSON: No objections. Please 32 8j MR. MORGAN: Okay. During my testimony today, i 9' I will provide information regarding West Beach operations and 101111i the engineering aspects of the proposed West Beach Secondary 11 Recovery Project. 12 (Off record comments) 13i West Beach Pool startup occurred in April 1993. The 141j field has been delineated by 11 penetrations consisting of 151; seven wells and four sidetracks. Three wells currently are 16; active: West Beach 4, West Beach 5B, and West Beach 6. i 17;' Exhibit B-3 is a plat showing the location of West Beach area 18! wells, including the three active wells, which are West 1911 Beach 4, 5B, and 6. Our recent efforts have focused on 20'!:t 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 2311 anticipated additional production from the West Beach 24 I! reservoir. 25 Secondary recovery plans at West Beach include water METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5I 6 7 8' 9 10 11 12 13 14 16 17 18 19' 20 21I 22 23 24 25 • • 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 water 33 flooding to be between 10 to 15 percent of the estimated 15 to 25 million stock tank barrels of oil originally in place. Augmenting water injection with gas 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 reservoir. The West Beach geologic model was updated in early 1998 to incorporate data from the West Beach 5 and West Beach 6 wells. 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 indicate a peripheral waterflood injecting into West Beach 6, which is the well down to the -- getting backwards here. Right there. And producing 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 I accelerate the base reserve profile, with little incremental METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 2 3i 4 I 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 34 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 be -- which should accommodate potential future drilling at West Beach. Recent drilling production and surveillance data from West Beach 4, 5B, and 6 have validated the modeling study and volumetrics. Post-fracture peak production from both West Beach 5 and West Beach 6 was initiated at 1,700 stock tank barrels of oil per day and 2,500 stock tank barrels of oil per day, respectively. Subsequently, production in West Beach 5B has fallen to 830 stock tank barrels of oil per day, primarily due to reduced reservoir pressures in the area due to the 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 �I connectivity between the wells. Lack of connectivity is a key risk to secondary recovery at West Beach. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 • 0 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 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 19I and previous log calculations. 20 Laboratory testing, core analyses, and geochemical 21 modeling indicate no significant problems with clay swelling or 2211 in-situ fluid compatibility. Analysis of a sample of West I� 2311 Beach 4 core in a lower quality interval indicates significant 2411 amounts of clay, 11 percent, may be present, primarily in the 25'1 form of Kaolinite. The presence of this clay may cause pore i METRO COURT REPORTING, INC. i� 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 3i wells are hydraulically fracture treated which will minimize 4 fluid velocities and subsequent fines movement in the rock near it 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 17I stream will be inhibited upstream of the Point McIntyre/West 181 Beach commingling point to prevent barium sulfate �1 19precipitation. Because West Beach has not produced any 201formation water, reservoir compatibility modeling and I 21laboratory testing assumed a water composition similar to that 22 1 of Point McIntyre. 231 Initially, the waterflood will be managed to replace 2411 reservoir voidage. As the flood progresses, injection rates i 25'I' will be adjusted in response to producing well surveillance and i METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 i'. Anchorage, Alaska 99501 j (907) 276-3876 I !i i • 37 1 performance. 2 New facilities installed and in service on the West 3 Beach Pad include a central manifold designed to collect 4 production from four initial wells and five additional wells. 5 The pad will also have a new chemical injection skid and a new 61 electrical distribution skid. A new 12 inch pipeline has been i 7 installed from the West Beach pad to drill site L1 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, 20i including potential additional drilling for West Beach or other 21 GPMA fields. Waterflood performance data will be key to 22ii assessing additional development potential at West Beach. 23 That concludes my testimony. 24I CHAIRMAN CHRISTENSON: Mike, I think I missed 2511 it in the first part. How many wells did you say you were j METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 i Anchorage, Alaska 99501 ji (907) 276-3876 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 1 MEN going -- intended to drill, additional wells? MR. MORGAN: Right now, we're -- we have no plans to drill additional wells until we get some response from the waterflood. And at that point, we will re-evaluate our plans for the field. CHAIRMAN CHRISTENSON: Okay. Gotcha. Thank you. No further questions. MR. MORGAN: Thank you. MR. GROTH: That concludes our testimony for the West Beach portion of the application. CHAIRMAN CHRISTENSON: Okay, sir. Thank you. Any further comments from the public with regard to the West Beach? Do you want to take a break? COMMISSIONER OECHSLI: Sure. CHAIRMAN CHRISTENSON: We're going to go off record here for about 10 minutes to do some deliberation, make sure we got all the questions. So if you would excuse us. (Off record 11:00 a.m.) (On record 11:12 a.m.) CHAIRMAN CHRISTENSON: We back on record? We've got a couple of questions -- further questions. General questions we would like you to answer -- I'll just tell you what the questions are, then you guys can figure out who you want to answer them. Question one. Are you planning to maintain voidage? METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5 6 7 8 9 10 11 12 16 17 18 19 20 21 22 23 24 25 • • c9M Question two. What are the initial and current reservoir pressures? And we would like you to elaborate a bit more on the paraffin build-up and any mitigation plans you might have, and your concerns there. MR. MORGAN: I think that's me. CHAIRMAN CHRISTENSON: Okay. Mike. MR. MORGAN: Regarding question one -- actually, if you could repeat it for me so I make sure I get them in the right order there. CHAIRMAN CHRISTENSON: Question one was are you planning to maintain voidage? Because you -- or make up voidage because you had talked about it staying the same or doing something like that and so we wondered if you were going to -- did that meant that you were making it up or are you just going to maintain what you're doing or where are you in the voidage picture? MR. MORGAN: I guess that's our initial strategy is to replace voidage but I think right up front, given that we're at, depending on which well you measure the pressure in, anywhere from 3,000 -- just above 3,000 pounds to 3,300 pounds we will exceed voidage from the wells, especially given West Beach 5 is not on line. CHAIRMAN CHRISTENSON: So you will actually make up and exceed that..... MR. MORGAN: Yeah. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 .-Anchorage, Alaska 99501 (907) 276-3876 40 !i 1' CHAIRMAN CHRISTENSON: .....ultimately? 2''MR. MORGAN: And I guess that leads into 3: question two which speaks to the initial pressures and current 4' pressures. Initial pressures were measured in West Beach 4, 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 71) psi in West Beach 4. Stand alone production from that well 8i through this year drew the reservoir pressure down to about 11 M' ill 121 3,500 pounds. And then we brought on West Beach 5B and West Beach 6 in July and August of 1999, and by November, we had seen the pressure fall in West Beach 5B which is in the updip area to just above 3,000 psi. And then also at West Beach 6, 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'I' 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 I 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 3 I 4 5 6 7 8 9 10 11 12 13 14' 15 16 17 18 19 20 21 22 23 24 25 • • 41 it historically in West Beach 4 but it's become severe in West Beach 5B. I don't have a schematic but that well is basically a 16,000 foot measured depth well with tubing down to about 13,800. It's three and a half inch tubing. We do have lift gas out to the well. Initially, at the 1,700 barrel a day rates, it was fine. And with even a small water cut associated! with the fracture treatment, we were able -- we didn't have too many paraffin problems but as the reservoir pressure declined and the rates in the well dropped pretty low down to around 800 barrels a day, we get severe paraffin build-up throughout that tubing to the point where it plugs off and we have to go out with coil tubing and clean it up. And so that's just a cost that we incur. What we expect, if -- when we get waterflood response from West Beach 6, is that the pressure will start to come back up and that we will be able to sustain production from that well. That's the current plan. CHAIRMAN CHRISTENSON: Okay. MR. MORGAN: It's similar to other wells at Point McIntyre and Nuyakuk that you get to those rates in these high departure wells. Temperatures drop pretty low. CHAIRMAN CHRISTENSON: Okay. Cammy, do you have any further questions? COMMISSIONER OECHSLI: I don't. Thanks. CHAIRMAN CHRISTENSON: I think that cleans us j up on the question area. METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2i 3 4 5 6 7 8 0 10 11 12 13 14 15 16 17 M 19 20 21 22 23 24 25 • • 42 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 then? MR. MORGAN: Yeah. CHAIRMAN CHRISTENSON: Great. Thank you. MR. MORGAN: You're welcome. MR. GROTH: If I may, one other point of clarification. CHAIRMAN CHRISTENSON: Sure. MR. GROTH: In our prepared testimony, we had mentioned a maximum injection rate of 10,000 barrels a day. That is, in fact, the name plate capacity on the pump equipment iI that we are planning to install. In the event that we see better than expected pump performance, we would ask that we have a maximum injection rate 15,000 barrels a day that the Commission consider that so that we're not back in here shortly soon after start up requesting another amendment. CHAIRMAN CHRISTENSON: Okay. So you want to change or expand I guess the injection rate from 10 to 15? j MR. GROTH: To 15 so that we've got some head METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 • • room for daily operations above name plate capacity on the equipment. CHAIRMAN CHRISTENSON: We'll look at that. I guess one point of clarification we have to do on this confidential thing, too. We are understanding the 2003 date and the information contained in those items we talked about there, to be only those items, and we're not going to retrograde back into other stuff that's already happened and records and stuff that we already have. And is that your understanding? 43 MR. GROTH: We concur with that understanding. CHAIRMAN CHRISTENSON: Okay. Good. Is there any other testimony or comments to be made today with regard to West Beach? No. Cammy, do you have anything else? COMMISSIONER OECHSLI: I don't. CHAIRMAN CHRISTENSON: I think we've completed it. And I would like to thank you for coming in and making a presentation. All good presentations. We appreciate the information. And that concludes our hearing for today. We'll adjourn. Thank you. i (Off record 11:18 a.m.) END OF PROCEEDINGS METRO COURT REPORTING, INC. 550 West Seventh Avenue, Suite 1650 Anchorage, Alaska 99501 (907) 276-3876 51 6 7 8 9 10 11 12 13 14 15 16 17 21 22 23 24 25 C E R T I F I C A T E UNITED STATES OF AMERICA) ) ss. STATE OF ALASKA ) I, Laura Ferro, Notary Public in and for the State of Alaska, and Reporter for Metro Court Reporting, do hereby certify: That the foregoing Alaska Oil & Gas Conservation Commission Public Hearing, was taken before me on the 13th day of January 2000, commencing at the hour of 9:03 o'clock a.m., at the offices of Alaska Oil & Gas Conservation Commission, 3001 Porcupine Street, Anchorage, Alaska; That the hearing was transcribed by me to the best of my knowledge and ability. IN WITNESS WHEREOF, I have hereto set my hand and affixed my seal this 18th day of January 2000. No ary Public in and for Alaska My commission expires: 05/03/01 METRO COURT REPORTING, 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 Amendment to Area Injection Order No. 413 Pt. McIntyre Testimony Z January 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. 1 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. 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 (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 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 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. All Pt. McIntyre water injection wells are completed with L-80 grade steel. All tubin Jewel is completed with 9-Cr/1 Moly, which is compatible with both L-80 and 13 -Cr. PMclntyre water? i , c rr ompletions are designed as sin le zone, sin le string with a single packer. Exhibits G- /' 1 through G-5 show typical wellbore —scTiematics for the five basic comp a ion designs. The current waterflood pattern configuration for the Pt. McIntyre Pool is an inve�nine-sThis pattern selection provides maximum flexibility for potential future convers 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. Future development plans will be based on field performance, including the performance of the j patterns already receiving MI. There are no plans to reduce well density below 40 acres. �J A surveillance program to monitor the Pt. McIntyre EOR 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 EOR project involves the eventual conversion of the existing 15 waterflood injectors and potentially any future water injectors to water -alternating -gas (WAG) 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 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. 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 slug size and i�r rrP^��^tai nil rFcovery for t e Pt Mcln yre n ance ai Recovery"'Frofe Zn:ee,,d at the LPC is expected to be delivered to Pt. McIntyre at a nominal 50 MMSCFD. hows the predicted incremental oil production rates for the Pt. McIntyre Enhanced Oil Sdroject for the next 23 years for the miscible gas injection rate of 50 MMSCFD. Exhibit shows the projected field oil production rates for the Pt. McIntyre base (primary/secondary) base plus EOR (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 EOR patterns mature, the availability of excess MI will allow additional pattern(s) to begin receiving MI. Nominally, two patterns will be receiving MI at any one 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 result o ifie project. r 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 EOR project at Pt. McIntyre is estimated to Pt. McIntyre EOR Project Application - Testimony 2 .,r V7 T M. • iDR-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, 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 original 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 (1850F). The thermal temperature bulb at Pt. McIntyre, due to source water injection, should provide an MMP buffer, but the project design was 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 the additional miscible injectant. This is a technically viable option and was part of the initial .U,> scoping studies for an EOR Project at Pt. McIntyre. However, when this initial evaluation indicated less favorable economics for this option, subsequent studies focused on self -generating MI project options. These studies resulted in the Owner decision to approve the funding of the 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 EOR Project Application - Testimony 3 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 (LPC) 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. 1 began work for ARCO at the Exploration and Production Research Center in Plano, 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. 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 extracted at th C will not be impacted by the EOR project. 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 �t�y 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 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 .il �r 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 Estimated Average Injection Pressure (psig) Pressure (psig) Pt. McIntyre Water Injection 2850 2250 Pt. McIntyre MI Injection 4500 4100 Pt. McIntyre Gas Injection 5000 4300 The estimated maximum injection rates for Pt. McIntyre enhanced recovery wells will not initiate o J4" a or propagate fractures through the confining strata, and, therefore, will not allow injection or ,,15 �,,•S 7 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 NAME - AFFILIATION (PLEASE PRINT) PUBLIC HEARING Januar 1$, 2000 9.00 AM PtMcIntvre/WBeach TELEPHONE Do you plan to testify? Yes No M1CN4AF- -- R. AnoRy�+r.1 � 3-�133Z yES r► s t PAI ren e4 rr1- X OM SG LI YVy► r i?AY A D4AAlf ,Z 6 s-/ 3 Z-- Y e s 7�oN —47ow-o�t ZGf GBy� yes Ma\IL LA 5�- 65-4 Lf plc �tt1��c. Evens Jot ( L 1 r►1 ►J �7 S -k C- ✓ice S - 4667cc- 713 - z z Sl n/o 10/ CL AQ- L-- RceyJ - A7-�' 0 2 G.5 -X7-0 9 �t'� 00 SP EXPLORATION ENGINEERING DATA � SHEET NO. OF SUBJECT BASED ON BU�DGE'T\/AFE NO. ENGINEER DEPT. APP'VL DATE �CA\(3t% �ILE NO. kvl I K rnu2n,iY 1-�7714,41vs C_ ARS.. L uNa>GaQA AK 2337-1 (3194) NC) cl-a "'It Ilk 3 - \'.)L A,R� 2C 3 -4-4 --53,7 A�CAD 26S-ho.Tc v4''e CIO 2-6 S - / 31 -2-- AV-e- AQC a Z (OS • "09 1-1-W CD Z6 -f- 6 91 y6 -43 ALASKA OIL AND GAS CONSERVATION COMMISSION December 1. 1999 Mr. J. W. Groth ARCO Alaska, Inc. PO Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Groth: TONY KNOWLES, GOVERNOR 3001PORCUPINE DRIVE ANCHORAGE. ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: X907) 276-7542 The Commission will hold a hearing on January- 12, 2000 concerning your November 8. 1999 application for authon'ty to initiate a waterflood 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 1) 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 between 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 below 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? What are the impacts of manufacturing injectant 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) What are the projected production rates for the next 23 years for miscible gas injection rates of 50 mmcf/d and 150 mmcf/d'? (Show primary_ recovery. «-aterflood 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'? If not why'? 8) What are the projections for H2S concentrations and associated problems. if any? WEST BEACH 1) The phi*h and structure map (annotated Nvith fluid contacts) used in generating the current volumetrics should be included in the exhibits. J.W. Groth 2 December 1, 1999 2) Are the net sand trends corroborated with seismic data, or are they based on a geologic model and well control? 3) W est Beach facilities envision it wells. do these include delineation wells? 4) Is the 10-15% incremental waterflood recovery estimate based on existing wells? Will additional wells increase incremental recovers? To what 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 vour 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 anv of the items listed above. Sincerely, Robert N. Christenson, P.E. Chair 42 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 of Publicat 0 0OAffidavit �► Ad # Run Dates ED Po # 217069 11/20/99 DN 02014016 Price per Account day $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. Legal ClerkC�'�_ Subscribed and sworn to me before this date: 6 UCMiC/6,'ZP,1z.:;L-z� Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES: Fill g ?e ---- —� —T ----------- '��ti�(uLrO�`' c PUBV of- , 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 Gommission, 3001 Porcupine Drive, Anchorage,Alaska 99501, and requesta hearing on this matter. If the protest is timely filed a hearing on the matter will be heldat the above address at 9:00 AM on January 12, 2000, in conformance with 20 AAC 25.540. If no protest isfiled, the Commission will con- sider 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. /s/Robert N. Christenson P.E., Chairman Pub.: 11/20/99 41 .r ARCO Alaska, Inc. Post Office B 036 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 Joe 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, J. W. Groth Attachments cc: D. W. Bose (AAI) ARCO Alaska, Inc. is a Subsidiary of AtlanticRichfieldCompany M. P. Evans (Exxon) J. Hurliman (BPA) 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. 4B 20 AAC 25.402 20 AAC 25.460 November 8, 1999 November 8, 1999 0 Table of Contents Section A - Application for Injection and Amendment to Area Injection Order No. 4B ....................1 Section B - Plat of Project Area........................................................................................................3 Section C - Operators/Surface Owners............................................................................................4 SectionD - Affidavit..........................................................................................................................6 Section E - Description of Operation................................................................................................7 Section F — Geologic Information.....................................................................................................9 Section G - Injection Well Casing Information................................................................................10 SectionH - 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 0 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 D-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. 413 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 (EOR) 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. 46, 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 EOR 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 EOR project. Planned startup for MI injection is the first quarter of 2000. Additional Pt. McIntyre EOR 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 EOR Project Application 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 EOR Project Application 0 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 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 Selection within Section 28 (ADL 414852) City of Barrow City of Barrow P. O. Box 629 Barrow, AK 99723 Parcel 16 (USS 9137) Lawrence Ahmaogak P.O. Box 411 Barrow, AK 99723 And 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 Parcel 17 (USS 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 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. Box 411 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 (USS 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 051-M) Engineering Field Activity NW Naval Facilities Engineering Command 19917 7th Ave., NE Poulsbo, WA 98370-7570 Pt. McIntyre EOR Project Application • Parcel 18 (USS 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 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. 4B. Pt. McIntyre EOR Project Application 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 LPC is expected to be delivered to Pt. McIntyre at a nominal 50 MMSCFD. At this rate, MI injection would occur for a period of approximately 23 years to inject the entire 35 percent HCPV 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 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 extracted at the LPC will not be impacted by the EOR project. Planned startup for MI injection is the first quarter of 2000. Modifications at the LPC 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 • 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 L1 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 EOR Project Application 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 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 "slimhole" 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 Infected Daily — Up to 150 million standard cubic feet per day. Compatibility with Formation and Confining 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 West Beach Type 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 Infected Daily — Maximum water injection requirements at West Beach are estimated at 10,000 BW PD. Compatibility with Formation and Confining 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 (SO4) associated with seawater breakthrough. However, the West Beach produced water stream will be inhibited upstream of the PM/WB commingling point to prevent BaSO4 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) Type 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 Iniected Daily — Maximum gas injection rates are estimated at 25 MMSCFD. Compatibility with Formation and Confining 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 1 - 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 Pt. McIntyre Water Injection Pt. McIntyre MI Injection Pt. McIntyre Gas Injection West Beach Water Injection West Beach Gas Injection Estimated Maximum Injection Pressure (psig) 2850 4500 5000 2850 4500 Estimated Average Injection Pressure (psig) (These pressures represent pump discharge pressures.) 2250 4100 4300 2100 4100 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 HRZ shales. The HRZ 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 HRZ 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 psi/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 EOR Project Application 14 Section K - Hydrocarbon Recovery 20 AAC 25.402(c)(14) Pt. McIntyre 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. 311 A 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. 46 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 e-� Greater Pt. McIntyre Area Drillsites and Pipeline Routing Map ® 6 New Pt. McIntyre EOR 0 0 0 0 0 0 0 0 0 New West Beach Pipelines Pipelines a 1 .1 �e.eee c�e.eeo ea.eee eem.een eee,ees eu.eee p�.eve B MBm I[rt11 �IMIIN Iw�wl 91NNf NIYIL NYI Plat of Wells Within Pt. McIntyre Participating Area er .eeo ere.eea en,eee ere.eae eex.eee e�,eee eee.eee ee4.eee 6 P2-14td r AYP,Y r XA 1 pa— -fAf 4d P2_22 P2-69 41 Ili—S1�-85 Px—tf2� r ♦ F2-9se�zADL e .. P2 f 365548 a f.`,',<i ,� P2-40'r P9-00 S o 'o • PS -08 • P2—fS PE -18 P2-49 PE -33 • P2-16 * &M-Sw Z PE -55 • ?2—f Atd A i Pi-01 _l2 P9-23 p2_27 P2-28 — � P2-68 • r • Pi— i-23 PP -21 P9—ea P2-� & N pt -11 P2-1 s • B PI -24 • P2-05 • P2-26 B • P1 • ♦ P2-29 a —92 TDP9—f7 ti • Pz —Of Fx—�0 , • m K• P!—f4 P9-51 _ PT: 2 Pf —12 {R • P — 17'1— 2 • PP.—$0 _ P2— 1V p� TX t Q g PI -20 • r�r��f `09"C —1 qq P9-44 P —42 P 0]d i.�1, E'�-kt)I� g .+ � ' Pf-oy J—JCS-0 • -4,41, • � l —77 :i�ts6-77 � wa r • Pl—o�t��lF`:rv'.;'iJ5 P � Kfi6c? P.E r4i�Ub'2 ADL 2 297 1— Pt—os AX 34J ADLPR7$6.27 Pf-2 Vf-3 • _ 54 A ffi P2—SO ♦� g 0 r.n.....=-•- • 0 o 0 0 2-48 .1 �e.eee c�e.eeo ea.eee eem.een eee,ees eu.eee p�.eve B MBm I[rt11 �IMIIN Iw�wl 91NNf NIYIL NYI Plat of Wells Within Pt. McIntyre Participating Area Pt. McIntyre Injection Wells Last ARCO Next MIT MIT Scheduled (Date) (Year) 06/21/97 2001 Last State 2002 07/06/98 2002 Minimum 2002 07/06/98 Injection Well Packer Depth 2002 Witnessed 2003 09/29/98 2002 Test Pressure 2002 07/06/98 2002 08/08/95 1999 Test Name API (Feet tvdss) (psi) (Date) P1 -G1 500292229800 8199 2050 06/21/97 P1-01 500292201800 8385 2096 None P1-14 500292233800 8328 2082 07/06/98 P1-16 500292234900 8641 2160 07/06/98 P1-21 500292236300 8610 2153 07/06/98 P1-25 500292193700 8750 2188 07/06/98 P2-09 500292287600 8846 2212 02/02/99 P2-15 500292240900 8870 2218 09/29/98 P2-16 500292239700 8742 2185 09/29/98 P2-23 500292245300 8850 2213 07/06/98 P2-28 500292255100 8860 2215 08/08/95 P2-29 500292240700 8685 2171 None P2-34 500292255800 4948 1500 08/23/98 P2-42 500292240500 8702 2176 07/06/98 P2-46 500292240100 8286 2072 07/06/98 P2-47 500292262800 8480 2120 06/13/96 Pt. McIntyre Injection Wells Last ARCO Next MIT MIT Scheduled (Date) (Year) 06/21/97 2001 05/11/98 2002 07/06/98 2002 07/06/98 2002 07/06/98 2002 07/06/98 2002 02/02/99 2003 09/29/98 2002 09/29/98 2002 07/06/98 2002 08/08/95 1999 03/17/98 2002 08/23/98 2002 07/06/98 2002 07/06/98 2002 06/13/96 2000 M X S W N I L A ra DS -LI WB -04 i ST 47E EC WB ST 1 ' LGI--05 LGI- " GULL L5-,25 S 5 T 2 -� = �i AAI, EX_ ON � ! Gi--0 L1-30' • IAL'" 628 L5-23 L1 -i4 L51694 1,G1._.,._ LGI-4 - .... 1 6+ �- L5-15 --! ✓ Plat of West Beach Pool/Participating Area (Possible Injection Wells are WB -04 or WB -06) • JVA e-� 7a NPB Plat of West Beach Pool/Participating Area (Possible Injection Wells are WB -04 or WB -06) Lei CULL IS ST I Tl WB Sr 3 WBS 3 T2 WB -05B WB -05 5A r r/} 6ilLL IS 31'"3' WB— _pb YYB, 06 ' Y WB -04 i Plat of West Beach Pool/Participating Area (Possible Injection Wells are WB -04 or WB -06) Lei • i �v 0 , 2 + SCALE IN MILES Ego 36 EGG i BLAND /^ USS9137 FF13033 1 6 STUMP+ BLAND + + SUM 2 SEAWATER WMT ,,, R USS4044 DOCK M PLANT L4 USS9267 too 0 FF111_954 + ° p DOCK 3 USS6905 Pw ° !T11322 o� 2S o O a p J y, p p � �o $ � o o t �-•� / i n °�a 1 i4 , lNt�7—DOCK -j✓p , J 9Vvi QOCX 311 C � f l r / p AC L/ ° P`E`� 2 , LI c�a / USS6906 F F11322 N PB STATE #i aa° T\ • j nn t} I ° D r,�i ° VN \ \, WEST \ tf e o f ° t ✓" o° f `�', t}. °per' y g , BEACH �c7 STATE a �G ° .�Q `.;Jb ! Af�G6 ABE1.0 . °° xJ3 0 c 1>6;- t�Rlfl �° T o o ° r• a L) % f �' A� 4 AGI (f „ 0 V�v ` daorl J�t�4o^ �. �. •-, v d n a + b lI _ a xn E�-PA� �� v a�oo ��! ;F.e, ��e - °"w"` QVC/ C 4PAD ` ` n ° u , R ° , Kc PAH', 9 ^, m d d Pt. McIntyre Area � } 3 36t 1 Allotment Location Map p. / no NORTH SLOPE ALASKA G� PAD SRC .lo� KITIZ If)-Id-QQ Exhibit C- I Exhibit D-1 Affidavit STATE OF ALASKA THIRD JUDICIAL DISTRICT I, J. W. Groth , declare and affirm as follows: 1. 1 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 1999, 1 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 (ADL 414852) City of Barrow City of Barrow P. O. Box 629 Barrow, AK 99723 Parcel 16 (USS 9137) Lawrence Ahmaogak P.O. Box 411 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 (USS 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 (USS 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. Box 411 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 (USS 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: 1999. J. W. Groth Declared and affirmed before me this day of 1 x �u `� , 1999. J Notary Public in and for Alaska My commission Expires: �j Il ItD Exhibit D-1 • Alternate Completion Interva if needed to augment water supply 0 Exhibit E-1 West Beach Shallow Section Type Log WB -1 •Gi Subsea JAN Depth ��• AIG t r AN l 3000 AN SV2 Initial Open Hole Gravel Pack Completion t-rarget for Sourcing-, Water 4(XX) 45(X lti .P I 4 �x t i 1 7 ; y i Exhibit E-1 West Beach Shallow Section Type Log WB -1 SV2 Initial Open Hole Gravel Pack Completion Target for Sourcing Water Alternate Completion Interval 3000 g if needed to augment water— ' supply , SV2 Initial Open Hole Gravel Pack Completion Target for Sourcing Water .2 Post WB6 Net to Gross West Beach Reservoir Net -To -Gross Ratio Map Post -Drill West Beach 6 using an 8% porosity cut-off m Structural X•Section West Beach 14B ST_3 M -058P61 M6 4 ma GULL IS ST_3 4 0 X 0 4m t- Isco -]t A 3w 454 1 West Beach West to East Structural/Stratigraphic Cross -Section • Exhibit G-1 Pt. McIntyre Well Schematic Conventional Gas Injection Well Design - P1 -G1 Exhibit G-1 Exhibit G-2 Pt. McIntyre Well Schematic Conventional Water Injection Well Design - 132-47 Exhibit G-2 r �J Exhibit G-3 Pt. McIntyre Well Schematic Slimhole Water Injection Well Design - P2-15 ftKB 2255 2256 TRSSSV NIP- PKR --- NIP NIP — TT _— Perf Pert-- - - tu i 1E f I { j i P2-15 APL' 500292240900 Spud: 18 -Feb -94 _ PBTD!' 12210 ftKB _ H2S. Ong Compltn: 08 -Mar -94 Max Hole48 deg @ 4042 _ Angle:, SSSV Type: Last W/� Angle TS: d c7 Annular Fluid: DIESEL T Ref Log Date 05 -Mar -94 Angle @ TD: 45 deg_ & 12220 Reference DIL _...-_-. Last Tag 21Jul-94 _ _ 4805 4806 Last T : - 12119' ELMD Last Update: 27 -Jun -98 Rev Reason: - SCH REVISION RKB: 1_47 It Well T .. INJ KOP: 10 111K Safety Notes Date Note 08 -Mar -94 Minimum ID: 3.750" OTIS XN NIPPLE 65 11705' MD General Notes Date Note 11597 - 11598 08 -Mar -94 Well Status: ACTIVE 08 -Mar -94 i Tubing Hanger. 4 1/2 _FMC NS Q 28' MD -Top Of Fluid Depth 0 11788 Last Th 0 12220 Casing Strings - All Size Weight IGrade Top Btm Feetrsescription 103/4 45.50 NT80 0'. _ 4380 75B -2970 NT80 --01 12210 4380UR. 1221pROD. CASING CASING - _....._... 11634- 11635 - Tubin Stn s -All Size Weigh Grade Top StmLFeetipescription 41/2 12.00 L-80 01 11727 11727 TUBING Gas Lift Mandrels/Valves _ t MD' TVD Man Man Vlv' Vlv Vtv, Viv Vlv Ylv Vlv Mfr Type ! Mfr. Type Latch Port TROT Run mme Type 1 4805' 4805' OTIS_ { ; OT ! DM -14W BK ' 0 _ 0.0 GLM 11655 -- 11656 2 11597 11597'.OTIS- 'AT' DM -14R' BK 0 0.0' GLM _Otherlucks, equip., eta JEWELRY --- - --- De Descri tion TypeIOTISXN a 5th 225:. TRS4-1/2" CAMCO TRDP SSSV, ID=3.812'_ i 11634 NIPOTIS X NIPPLE. ID=3.813" 11655 PKR7-5/8" x 4-1/2" BAKER SABL_-3 PACKER _ 11689 NIPOTIS X NIPPLE.ID=3.813" 11705' NIP NIPPLE, 0=3.75" 11727 TT TUBING TAIL, WLEG 11714' ELMD 11689 11690 Perforations Summary Interval Zone Status ! Feet SPF Date Comment !Type 11790-11830 40' 6 21 -Jul -94 I 11920-11970 1 50': 6 21 -Jul -94 i i 11705 11706- 170611727- � 11727- I i 11726 -• 9 11800 11810- 118:20- 1810 11820Perf 11940 - j 11960: Exhibit G-3 Exhibit G-4 Pt. McIntyre Well Schematic Ultra Slimhole Water Injection Well Design - P2-09 500- 00-100015001 a.omny.ou mea. inn Size Wei ht Grade To 1000- 7 26.00 0 15001 95/8 40.00 k 2000-i SSSV Nip I` Size YVeight TGrade lop --- WRSSSV / 4 12 12.60 2500- 500-3000-3500-4000-4500 Gas Lift M_andrelsNalves 3000- Man Vlv Type Mh 12116 - 12166 3500- KBG-2-L CAI 60 degree 4000- KBG-2-LCA �HJ II 45M 5000 I 5500 - 3-3/8" degree 6000 -, I 6500 - 7000 - 7500- 500-8000 8000- i 8500- 500-9000-- 9000- 9500- 9500-10000- 10000- 10500 -- 10500-11000 11000- 11500 - PKR 12000 - NIP - NIP —' 12500 - TUBING = TAIL 09 SL H2S: SSSV Type_; Annular Fluid:.. Reference L :; Last Tag: Rev Reason: Well T Safet r�Note: Diesel to 4000', Ref Log L SW 4000'-11899' SWS CET Last SSSV 4.5" NIP W RSSS\ OO PKR BA? Max Hole � 56 deg @ 1 Vlv VN Vlv Vivi Vlv Latch Port TRO Run Commen Type BTM I 0 0.01 -May -98 INT I 1119551 TUBING TUBING TAIL WI WEG 11964' ELM) TAIL cuwu- Iguru a.omny.ou mea. inn Size Wei ht Grade To lou oe9ree 7 26.00 0 HJ 11 95/8 40.00 0 Tubing_Strings . All proposed Size YVeight TGrade lop --- 4 12 12.60 squeeze Gas Lift M_andrelsNalves t MD' TVD IMan Mfr Man Vlv Type Mh 12116 - 12166 1 4553i 4553; CAMCO KBG-2-L CAI 60 degree 2 11832I 11832' CAMCOI KBG-2-LCA SSSV 4.5" NIP W RSSS\ OO PKR BA? Max Hole � 56 deg @ 1 Vlv VN Vlv Vivi Vlv Latch Port TRO Run Commen Type BTM I 0 0.01 -May -98 INT I 1119551 TUBING TUBING TAIL WI WEG 11964' ELM) TAIL cuwu- Iguru [v o ra-u urryi rsra lou oe9ree HJ 11 phasing: RDX proposed squeeze s 12116 - 12166 50 6 11 -Jul -983-3/8" 60 degree �HJ II phasing; 1UC4.3,2 RDX 12264 - 12284 _ 20 6 11-Jul-9� 3-3/8" degree HJ II 160 phasing; UB1 Exhibit G-4 Exhibit G-5 Pt. McIntyre Well Schematic Mono -bore Water Injection Well Design - P2-34 ftK6 2091- 2092- '.. 6231-, 6232; 6383- 6384 _ 12820- 12821 - 12900-12905-12910-12915 12920 - 13080 - 13090 - 13100- 13110 - . SSSV NIP { ( i ' i PKR —' - NIP Perf - Perf '. P2-34 API: 15002922558001 Sud: 30 -Jun -95 1 PBTD: 13326 ftKB H2S: I Orig Compltn: 20 -Jul -95 Max Hole 55 deg aQ 8279 An le: SSSV Type: Last W/O: Angle Q TS`degA_ Annular Fluo_l DIESEL T Ref LcgOate: 14-Ju1-0An�c le Cad TD: 49 deg @ 13327 Reference I SWS CDR/GR Last Tag 14 -Jul -98 Log: I Date: Last Tag;_L3092' SLMD_ Last U_ ate: 24 -Au -98 Rev Reason:' PULL PX PLUG RKB: 52 ft WeG Typed INJ KOP:, 0 ftKB SafetyNotes....... Date_ N_ote _ 20.1ul-95 Minimum ID: 4.562" PARKER SWS NIPPLE cM 2091' MD General Not. Date Note 2G -Jul -95 Well Status. ACTIVE 20-JuF95 'Tubing Hanger FMC 3T MD-. _- Top Of Fluid th 12894 _ Last Tag Depth Q 13326 Casino Strings - All Size Wei ghtIGrade Top Btnt Feet Description 9 518 47.00L80 0 6533 _ 65331_PROD. CASING _ Tubing Strings Size 1Weight_ Grade ;_ Top _. Btm Feed Description_ 512 1200 NT80 0 13326 73326iTUBING Gas lift Mandrels/Valves tr MD TVD ManMan Mfr Vlv Type Mfr Vlv Type Vlv Vlv VW Vlv Latch Port TRO Run T e Vlv mman 1 6231 6231 HES-LB '.OT D -14R RA 1 0 0.0 GLM Other (Pius, ss, equip, etc.) -_J _ LRY -- De th Type IDascriPtion 2091 SSSV 15-1/2" PARKER SWS NIPPLE, tD=4.562" NIP i 6383 PKR 9-5/8"_X 5-1/2" BAKER LINER TOP 2X_P_ PACKER _ 12820 NIP PARKER SWS NIPPLE, ID=4.562" Perforations Summary Interval ;Zone I Status Feet SPF Date Type Comment 12896-12921 1 1 251 6'01 -Au -91 13070 -13120 1 1 501 6 01 -Aug -9 Exhibit G-5 Well: WB -04 GPMA WEB Date: 4!15/99 ftKB i WB -04 API: 500292211700 Well Type: PROD Angle @ TS: deg @ 2281 SSSV SSSV Type: CAT I - SSSV Orig Compltn: 8/8/91 Angle @ TD: 31 deg @ 1491 Annular Fluid: 30000 DI Last W/O: Rev Reason: 2282 Reference GR/DIL/LDT/CNL Ref Log Date: 6/6/91 Last Update: 5/19/98 Log: Last Tag: 14910 TD: 14909 ftKB Last Tag Date: Max Hole 65 deg @ 9400 4771 Angle: Safety Notes 4772 Date Note 6/15/91 Minimum ID: 2.750" OTIS'XN' NIPPLE 14124' MD General Notes 8735 Date Note 6/15/91 Tubing Hanger. RKB @ 25' MD 8736 6/15/91 Well Status: ACTIVE Last Tag Depth @ 14910 Top Of Fluid Depth a 14549 11208 Other (plugs, equip., etc. - JEWELRY Depth TVD Type Description ID 2281 2243 SSSV 3-1/2" OTIS FMX SC SSSV, I0=2.813" 2.81 13056 7691 PKR 9-5/8" x 3-1/2" BAKER'D' PACKER 3.00 11209 12536 14124 8442 NIP OTIS XN NIPPLE, ID=2.75" 2.75 14430 8696 TT TUBING TAIL ELMD 14428' ELMD 4.00 12537 Casing Strings -All Size Weight Grade Top Btm Feet Description 12936 13.375 72.00 L-80 0 4928 4928 SUR. CASING 9.625 47.00 L-80 0 13443 13443 PROD. CASING 12937JIL,7.000 29.00 L-80 13145 14508 1363 LINER 5.000 18.00 13CR 14208 14909 701 LINER Tubing Strings - All 13056 PKR Size Weight Grade Top Btm Feet Description 3.500 9.30 L-80 0 14147 14147 TUBING -IPC 3.500 9.30 13CR 14147 14446 299 TUBING Gas Lift Mandrels/Valves 13057 Stn MD TVD Man Man V Mfr V Type VOD Latch Port TRO Date Viv Mfr Type Run Comm 1 4771 3925 CAMCO MMG CA RD 1.5 RK 0.000 0 GLM (9CR) 13145 2 8735 5742 CAMCO MMG CA RD 1.5 RK 0.000 0 GLM (9CR) 3 11208 6839 CAMCO MMG CA RD 1.5 RK 0.000 0 GLM 14124 NIP (9CR) 4 12536 7431 CAMCO MMG CA RD 1.5 RK 0.000 0 GLM 14125(9CR) 5 12936 7625 CAMCO MMG CA E 1.5 RKP 0.000 0 GLM 9CR Perforations Summary Interval TVD Zone Status Feet SPF Date Type Comment 14550- 8798-8840 50 4 7/4/91 14600 14620- 8857-8954 114 46/30/91 144301 TT 14734 14754- 8971-8988 20 4 7/3/91 14431 Pert 14774 P14560 Pert 14700 Perf 14760 14770 I Exhibit G-6 Well: WB -0 GPMA 6 WEB Date: 6/16/99 ftK6 SL SSSV WB -06 API: 500292292900 Well Type: PROD Angle @ TS: deg @ 2010 SSSV Type: CAT I Ong Compltn: Angle @ TD: 55 deg @ 1821, Annular Fluid: Diesel & Last W/O: Rev Reason: High tag Seawater (carbolite) Reference Ref Log Date: Last Update: 6/13/99 2600 2605 Log: Last Tag: 16213' SLM TD: 18700 ftKB 7020 Last Tag Date: 6/12/99 Max Hole 69 deg @ 10979 Angle: 7250 Safety Notes Date Note 9505- 2/2/99 Minimum ID = 3.725" at XN nipple 17393' MD. 3/16/99 Frac Sleeve 2.9" ID 49' long set on 3/14/99 1975' SLM 12190 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 du 12195 a SWS RFT. 14595 Fish - FISH Depth Description Comment 18111 RFT PARTS RFT BOLTS Other (plugs, equip., etc. - JEWELRY Depth TVD Type Description ID 2008 1986 SSSV CAMCO 4-1/2" TRM-4E TRSSSV 3.811 16305 17298 8760 NIPPLE X NIPPLE 3.81( 17309 8765 PKR BAKER 7" X 4.5" MODEL S-3 HYDRO SET PACKER 3.88( 17372 8797 NIPPLE X NIPPLE 3.81( 17235 17393 8808 NIPPLE XN NIPPLE (w/ C -SUB ran 5/23/99) 3.72( 17404 8814 TT BAKER WLEG 17405' ELMD 4.00t Casing Strings - All 17298 NIPPLE Size Weight Grade Top Btm Feet Description 13.380 68.00 L-80 0 7261 7261 Surface 9.630 47.00 L-80 0 13694 13694 Intermediate 17299 9.630 47.00 L-80 13694 16042 2348 Intermediate 7.000 29.00 L-80 15814 16913 1099 Production PKR ' 7.000 29.00 13CR-80 16913 18210 1297 Production 17309 17310 TubingStrings - All Size Weight Grade Top Btm Feet Description 4.500 12.60 L-80 0 17405 17405 Tubing 17311 Gas Lift Mandrels/Valves 17312 Stn MD TVD Man Man V Mfr V Type VOD Latch Port TRO Date Vlv, Mfr Type Run Commc 1 2599 2516 CAMCO MMG CAMCO DMY 1.5 RK 0.000 0 6/3/99 17372 NIPPLE 2 7017 4603 CAMCO MMG CAMCO DMY 1.5 RK 0.000 0 5/15/99 3 9501 5617 CAMCO MMG CAMCO GLV 1.5 RK 0.250 2496 5/25/99 17373 4 12188 6612 CAMCO MMG CAMCO DMY 1.5 RK 0.000 0 5/16/99 17374 5 14592 7604 CAMCO MMG CAMCO GLV 1.5 RK 0.000 2471 5/25/99 6 16300 8304 CAMCO KBG-2 CAMCO MEMORY 1.0 BK 0.000 0 5/26/99 GAUGE 7 17231 8726 CAMCO KBG-2 CAMCO OV 1.0 BK 0.250 0 5/27/99 17393 NIPPLE Perforations Summary Interval TVD Zone Status Feet SPF Date Type Comment 17394 17860- 9060-9188 O 230 4 3/3/99 IPERF 60 deg phasing 18090 Stimulations & Treatments Interval Date Type Comment 17404 TT 17860 - 18090 3/6/99 FRAC 30,000 Ibs of 20/40 LWP 17860 - 17967 3/17/99 FRAC 38,400 lbs of 20/40LWP 17405 FRAC 17860 - 17967 5/19/99 FRAC 124,655 lbs or 20/40 LWP 17900 18000 FRAC FRAC RFT PARTS 18112 18700 J L Exhibit G-7 Exhibit H-1 Pt. McIntyre Miscible Injectant Compositional Analysis Exhibit H-1 Mole Component Percent Nitrogen 0.41 Carbon Dioxide 9.26 Methane 58.01 Ethane 11.76 Propane 16.15 Iso -Butane 1.70 N -Butane 2.49 Iso -Pentane 0.12 N -Pentane 0.08 Hexane 0.02 Heptane Plus 0.00 Exhibit H-1 0 Exhibit H-2 • Composition from 9/26/97 Sample # 44590 Exhibit H-2 LPC Reinjection Gas Component Value Unit Hydrogen Sulfide 40 ppm Carbon Dioxide 7.34 mole % Nitrogen 0.65 mole % Methane 79.88 mole % Ethane 7.3 mole % Propane 3.75 mole % I -Butane 0.39 mole % N -Butane 0.62 mole % I -Pentane 0.04 mole % N -Pentane 0.03 mole % Hexane + 0 mole % Specific Gravity 0.7171 Composition from 9/26/97 Sample # 44590 Exhibit H-2