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Home My WebLink AboutAIO 003 BAREA INJECTION ORDER 3B Prudhoe Bay Unit Prudhoe Bay Oil Pool North Slope, Alaska 1. July 17, 2015 BPXA's request for amendment of Pool Rule 9 and modification of AIO 3A and AIO 4F (appendix held confidential in secure storage) 2. July 20, 2015 Notice of public hearing, affidavit of publication, email distribution list, and mailings 3. July 23, 2015 Revised notice of public hearing, affidavit of publication, email distribution list, and mailings 4. August 19, 2015 CPAI's comments 5. August 25, 2015 BPXA's comments (appendix held confidential in secure storage) 6. August 27, 2015 Public hearing transcript (held in CO 341 F), sign -in sheet, public testimony, presentations (portion of presentation held confidential in secure storage) 7. September 3, 2015 CPAI's supplemental submission 8. September 4, 2015 Email re: supplemental information on CO2 disposal 9. September 8, 2015 BPXA's post hearing submissions (portions held confidential in secure storage) 10. March 7, 2016 BPXA's request to continue WAG Injection Operations (AIO 3B.001) 11.-------------------- Background information 12. July 27, 2016 BPXA's request to continue WAG Injection Operations PBU S-41A (AIO 313.002) 13. July 28, 2016 BPXA's request to continue WAG Injection Operations PBU X-24A (AIO 313.003) 14. September 7, 2016 BPXA's request to continue WAG Injection Operations PBU P-06B (AIO 3B.005) 15. February 2, 2017 BPXA's request to continue WAG Injection Operations PBU Z-19A (AIO 3B.006) 16. February 9, 2017 BPXA's request to continue WAG Injection Operations PBU R-02 (AIO 3B.007) 17. February 26, 2017 BPXA's request to continue WAG Injection Operations PBU S-I I (AIO 3B.008) 18. November 12, 2018 BPXA's request to continue WAG Injection Operations PBU V-05 (AIO 3B.009) 19. December 8, 2019 BPXA request to cancel aio3b.007 (aio3b.007 cancel) 20. June 29, 2021 Hilcorp's request to cancel AIO 3B.002 ORDERS 0 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska) Inc. for amendments to Area Injection Order 3A to authorize the injection of carbon dioxide effluent from the proposed Alaska LNG Project gas treatment plant for the purposes of enhanced oil recovery, and the request from ConocoPhillips Alaska Inc. to authorize disposal of the carbon dioxide effluent. IT APPEARING THAT: Docket Number: AIO-15-032 Area Injection Order No. 313 Prudhoe Bay Unit Western Operating Area including the K Pad Area Prudhoe Oil Pool North Slope Borough, Alaska October 15, 2015 1. By application received July 17, 2015, BP Exploration (Alaska) Inc. (BPXA) on behalf of itself and ExxonMobil Alaska Production Inc. (ExxonMobil) as working interest owners (WIOs) in the Prudhoe Bay Unit (PBU) requested that Area Injection Order (AIO) 3A be amended to allow the injection of carbon dioxide (CO2) for enhanced recovery and pressure maintenance purposes from sources inside and outside the PBU. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) scheduled a public hearing for August 27, 2015. On July 20, 2015, the AOGCC published notice of that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 21, 2015, the notice was published in the ALASKA DISPATCH NEWS. 3. On July 23, 2015, the AOGCC published notice of that the location of the hearing had changed on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the Notice of Public Hearing to all persons on the AOGCC's mailing distribution list. On July 24, 2015, the notice was published in the ALASKA DISPATCH NEWS. 4. By letter received August 19, 2015, ConocoPhillips Alaska, Inc. (CPAI) on behalf of itself and Chevron U.S.A. Inc. (Chevron) as PBU WIOs supported BPXA's request to allow the injection of CO2 for enhanced recovery purposes, but also asked for authorization to dispose of the CO2 in the event that CO2 is not shown to provide any enhanced oil recovery benefit. 5. On August 25, 2015, the AOGCC received pre -filed written testimony from BPXA. 6. On August 27, 2015, the AOGCC received a letter from ExxonMobil supporting BPXA's application. Area Injection Order 313 • • October 15, 2015 Page 2 of 7 7. The hearing commenced at 9:00 AM on August 27, 2015, in the Alaska State Legislature Building, Legislative Information Office located at 716 West 4th Avenue, Anchorage, Alaska. 8. Testimony was received from representatives of BPXA, CPAI, and Mr. Tom Lakosh, a private citizen. 9. The record was held open until September 8, 2015 for responses to requests made by the AOGCC at the public hearing. 10. The AOGCC received written comments from Mr. Lakosh on August 27, 2015, requested additional information from CPAI on September 3, 2015, and requested additional information from BPXA on September 8, 2015. 11. By email sent September 4, 2015, the AOGCC requested CPAI provide further justification for its request to dispose of CO2. CPAI responded that same day. FINDINGS: Operator and Owners: BPXA is the operator of the leases in the portion of the PBU within the Affected Area of this order. BPXA, ExxonMobil, CPAI, and Chevron are the WIOs, and the State of Alaska, Department of Natural Resources (DNR) is the landowner of the Affected Area, which is located within the North Slope Borough, along Alaska's northern coastline. 2. Affected Area: The Affected Area is defined in AIO 3A, and it remains unchanged for this amended order. 3. AOGCC Authority: The U.S. Environmental Protection Agency (EPA) has granted the AOGCC regulatory primacy limited to underground injection control (UIC) Class II wells. 4. Source of CO2 Effluent: The proposed Alaska Liquefied Natural Gas Project (AK LNG) includes a North Slope gas treatment plant (GTP) to process produced gas from multiple fields to sales specifications prior to shipment to the proposed LNG plant in south-central Alaska. The GTP will remove significant amounts of impurities from the produced gas — primarily CO2—prior to shipment for sales. The resulting effluent stream from the GTP is expected to contain more than 99% CO2, and it will be sent back to the PBU for injection. 5. BPXA Request: BPXA requests that AIO 3A be amended to authorize the injection of the portion of the effluent stream that is sourced from fields outside of the PBU for enhanced oil recovery (EOR) purposes. AIO 3A currently authorizes injection of produced gas that originates within the PBU. 6. CPAI Request: CPAI supports BPXA's request for authorization to inject the GTP effluent stream for FOR purposes, but is additionally requests authorization to dispose of the GTP effluent stream if it is determined there is no FOR benefit to injecting that effluent stream into the Prudhoe Oil Pool (POP). CPAI also requests AIO 3A be amended to permit administrative approval of future modifications. 7. FOR Potential of CO2: Under the right conditions, mixtures of CO2 and the hydrocarbon miscible injectant already in use for FOR purposes within the PBU will be miscible with the crude oil and thus provide an FOR benefit. In the event that mixtures containing CO2 are Area Injection Order 3B • • October 15, 2015 Page 3 of 7 not miscible, injecting the CO2—bearing effluent stream will improve oil recovery by maintaining reservoir pressure. 8. CO? Disposal: According to the EPA, CO2 can be disposed of in Class II wells when those wells were previously used for a CO2 FOR injection project. Disposal of CO2 under other circumstances requires Class VI wells, which are administered by the EPA. 9. Administrative Relief: Rule 10 of AIO 3A provides for administratively amending the order if certain conditions are met, but is an older form of the rule than the AOGCC currently uses. CONCLUSIONS: 1. Amendment of AIO 3A is necessary to authorize the injection of outside substances. 2. Injection of the effluent stream from the AK LNG GTP in the Prudhoe Oil Pool will improve recovery and minimize waste. 3. CPAI's proposed disposal injection of CO2-bearing effluent derived from the GTP requires use of UIC Class VI wells, which are under the jurisdiction of the EPA. 4. AIO 3A's administrative relief rule should be revised to be consistent with the AOGCC's current practices. NOW, THEREFORE, IT IS ORDERED: AIO 3 and AIO 3A and all associated administrative approvals (except AIO 003.011, AIO 003.012, AIO 003.016, AID 003.019, AIO 003.022, AIO 003.024, AIO 003.029, and AIO 003.030, which remain in effect) are hereby revoked and replaced by this order. All information related to AIO 3 and AIO 3A is hereby incorporated by reference into the record for this order. The following rules, in addition to the statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), govern Class II injection operations in the affected area described below: Affected Area: Umiat Meridian Township and Range Sections T10N R12E Sections 1 through 4: All Sections 10 through 12: All T10N R13E Sections 1 through 16: All Section 24: All T10N R14E Sections 5 through 8: All Sections 17 through 20: All T11N R11E Sections 1 through 4: All Sections 9 through 15: All Sections 24 and 25: All T11N R12E Entire Township T11N R13E Entire Township T11N R14E Sections 3 through 8: All Sections 17 through 20: All Sections 29 through 32: All T12N R10E Sections 13 and 24: All Area Injection Order 313 • • October 15, 2015 Page 4 of 7 T12N R1 lE Sections 9 through 30: All Sections 32 through 36: All T12N R12E Section 7: All Section 17 through 36: All T12N R13E Sections 19 through 23: All Sections 26 through 36: All T12N R14E Sections 27 through 29: All Sections 31 through 34: All Rule 1 Authorized Iniection Strata for Enhanced Recovery(Source: AIO 3A.002 and Revised This Order) Within the affected area and in the strata defined as those strata which correlate with the strata found in ARCO Alaska Inc. (Atlantic -Richfield -Humble) Prudhoe Bay State Well No. 1 between the measured depths of 8110 feet and 8680 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: (a) Produced water and gas from Prudhoe Bay Unit processing facilities; (b) CO2 and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; (c) Enriched hydrocarbon gas; (d) Non -hazardous water and water based fluids — (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); (e) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; V. Glycols; vi. Radioactive tracer survey fluids (f) Non -hazardous glycols and glycol mixtures; (g) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides (h) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. Area Injection Order 313 • • October 15, 2015 Page 5 of 7 Rule 2 Authorized Injection Strata for Disposal (Source: AIO 3.001) Within the affected area, non -hazardous oil field fluids may be injected for the purpose of fluid disposal into strata defined as those strata which correlate with the strata found in SAPC's Prudhoe Bay Unit Well No. C-11 between the measured depths of 3416 feet and 6293 feet. Rule 3. Fluid Iniection Wells (Source: AIO 3) The underground injection of fluids must be: (i) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; (ii) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or (iii) through a well that existed as a service well for injection purposes on the date of July 11, 1986 Pumping of excess non -hazardous fluids that are developed solely from well operations or necessary to control the fluid level of reserve pits, into surface/production casing annuli is exempted from the above requirements. Rule 4. Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 3A) The tubing by casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. Rule 5. Reporting the Tubing/Casing Annulus Pressure Variations (Rescinded: AIO 3A) Rule 6. Demonstration of Tubing -Casing Annulus Mechanical Integrity (Source: AIO 3A) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter (except at least once every two years in the case of a slurry injection well). The AOGCC must be notified at least 24 hours in advance to enable a representative to witness mechanical integrity tests. Unless an alternate means is approved by the AOGCC, mechanical integrity must be demonstrated by a tubing by casing annulus pressure test using a surface pressure of 1500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater, that shows stabilizing pressure and does not change more than 10 percent during a 30-minute period. Results of mechanical integrity tests must be readily available for AOGCC inspection. Rule 7. Well Integrity Failure (Source: AIO 3A) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the Operator shall notify the AOGCC by the next business day and submit a plan of corrective action on a Form 10-403 for AOGCC approval. The Operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the AOGCC. A monthly report of daily tubing and casing annuli pressures and Area Injection Order 3B • • October 15, 2015 Page 6 of 7 injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8. Pluimin%! and Abandonment of Fluid Injection Wells (Source: AIO 3) An injection well located within the affected area must not be plugged or abandoned unless approved by the AOGCC. Rule 9. Wells Authorized for Downhole ComminIlled Injection with the Aurora Oil Pool (Source: AIO 3.010 and AIO 3A) Injection into the AOP and POP within the same wellbore is authorized for wells PBU S-09 and S-31A, subject to the following conditions. (a) An approved Application for Sundry Approval (Form 10-403) is required for each well prior to commencement of commingled injection. (b) Within 60 days of commencement of commingled injection in a well, or switching from one injection fluid to the other, BPXA must conduct an injection survey to determine the proper allocation of injected fluids. Additional injection surveys shall be conducted on each well at least once per year thereafter as long as the well continues commingled inj ection. (c) Annual and total cumulative volumes injected by pool and results of logs or surveys used for determining the allocation of injected fluids between pools must be supplied in the Annual Surveillance Report for the AOP. Rule 10. Administrative Relief (Revised this order) 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. DONE at Anchorage, Alaska and dated October 15, 2015. Cathy . Foerster Chair, Commissioner Daniel T. Seamount, Jr. Commissioner Area Injection Order 3B • • October 15, 2015 Page 7 of 7 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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. 0 • Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Thursday, October 15, 2015 3:32 PM To: AKDCWeIIIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Suzanne Gibson; Sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Don Shaw; Donna Vukich; Eric Lidji; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jilt.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker; Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA) Subject: Area Injection Order 3B and 4G (Prudhoe Bay Unit) Attachments: aiIRpdf, aio4g.pdf • Please see attached. Samantha Carlisle Executive Secretary II .Alaska Oil and i�as Conservation Commission 333 West 7" .Avenue -Anchorage, .AC 99501 (907) 793-1223 (yhone) (907) 276-7542 (fax) CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1223 or Samantha.Carhsle@alaska.gov. 0 • Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99731 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Or. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Dave P. Lachance Richard Wagner Darwin Waldsmith Vice President, Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 4A.e:LqL do-ko�ar ��tt 20 \rj Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.001 Mr. Douglas A. Cismoski Wells Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.claska.gov Re: Docket Number: AIO-16-008 Request for administrative approval to allow well W-24 (PTD 1880700) to be online in water alternating gas (WAG) injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) W-24 (PTD 1880700) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated March 7, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA has determined that W-24 exhibits inner annulus pressure falloff of approximately 11 psi/day while on water injection. The required differential pressure between the IA and OA cannot be maintained without frequent interventions. BPXA performed diagnostics including a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on January 26, 2016 and a passing non -state witnessed Mechanical Integrity Test of the Outer Annulus (MITOA) on February 12, 2016 which indicates that W-24 exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 3B.001 March 15, 2016 Page 2 of 2 AOGCC's approval to continue WAG injection in PBU W-24 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is January 26, 2016. DONE at Anchorage, Alaska and dated March 15, 2016. 0 Cathy .- Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERA' 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, March 1S, 2016 10:49 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Amanda Tuttle; Andrew VanderJack; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock; Bruce Webb; Burdick, John D (DNR); Caleb Conrad; Cliff Posey; Colleen Miller; Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Gregg Nady; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Karen Thomas; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Mealear Tauch; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Stephen Hennigan; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Ann Danielson; Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster; William Van Dyke Subject: aio3b-001 (BPXA) (PBU) Attachments: aio3b-001.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Douglas A. Cismoski Richard Wagner Darwin Waldsmith Wells Intervention Manager P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 VVI,_2rcVA, 5 , 2 41 C, Angela K. Singh THE STATE 0IA.I.AJKL'1 GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.002 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-16-029 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well S-41 A (PTD 2101010) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) S-41A (PTD 2101010) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated July 27, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on November 18, 2015 which indicates that S-41 A exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 90 to 150 psi/day while on gas service, and no history of repressurization when on water injection. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AIO 3B.002 August 2, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU S-41A is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; R1 7 After well shut in due to a change in the well's mechanical condition, AOGCC shall be required to restart injection; and 1 The MIT anniversary date is November 18 2015. / �'' DONE at Anchorage, Alaska and dated August 2, 2016. Cath P. Foerster $aneielT. S ount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE reins rrencn 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. Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Wednesday, August 03, 2016 12:23 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); French, Hollis (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Various Administrative Approvals Attachments: aio4G.001.pdf, aio3B.002.pdf, aio3B.003.pdf Please see attached. Docket Number: AIO-16-029 Request for administrative approval to allow well S-41A (PTD 2101010) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) S-41A (PTD 2101010) Prudhoe Bay Field Prudhoe Oil Pool Docket Number: AIO-16-030 Request for administrative approval to allow well 09-25 (PTD 1840280) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 09-25 (PTD 1840280) Prudhoe Bay Field Prudhoe Oil Pool Docket Number: AIO-16-031 Request for administrative approval to allow well X-24A (PTD 1991250) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) X-24A (PTD 1991250) Prudhoe Bay Field Prudhoe Oil Pool Jody J. Colombie AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7" .Avenue Anchorage, Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Cam,-- - Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.003 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-16-031 Request for administrative approval to allow well X-24A (PTD 1991250) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) X-24A (PTD 1991250) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated July 28, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on June 7, 2016 which indicates that X-24A exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 90 psi/day while on water injection. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AIO 3B.003 August 2, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU X-24A is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical shall be required to restart injection; and 7. The MIT anniversary date is June 7, 2016. DONE at Anchorage, Alaska and dated August 2, 2016. C thy . Foerster Va2riel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE Hollis French 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. Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Wednesday, August 03, 201612:23 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); French, Hollis (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWeIIIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; gspfoff; Hyun, James 1 (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, lames M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: Various Administrative Approvals Attachments: aio4G.001.pdf, aio3B.002.pdf, aio3B.003.pdf Please see attached. Docket Number: AIO-16-029 Request for administrative approval to allow well S-41A (PTD 2101010) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) S-41A (PTD 2101010) Prudhoe Bay Field Prudhoe Oil Pool Docket Number: AIO-16-030 Request for administrative approval to allow well 09-25 (PTD 1840280) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) 09-25 (PTD 1840280) Prudhoe Bay Field Prudhoe Oil Pool Docket Number: AIO-16-031 Request for administrative approval to allow well X-24A (PTD 1991250) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) X-24A (PTD 1991250) Prudhoe Bay Field Prudhoe Oil Pool Jody J. Co(ombie AOGCC Specia( ssistant Alaska Oi(andGas Conservation Commission 333 %West 711 Avenue Anchorage, Alaska 99501 Office: (907) 7.93-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.gov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 (Y, (@ cf Angela K. Sing% THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 311.004 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-16-032 Replacement Administrative Approval Prudhoe Bay Unit W-42 (PTD 1880570) Prudhoe Bay Field; Prudhoe Oil Pool Dear Mr. Daniel: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov On its own initiative, the Alaska Oil and Gas Conservation Commission (AOGCC) RESCINDS and REPLACES Administrative Approval AIO 3.026 which allows Prudhoe Bay Unit W-42 (PBU W-42) to continue injection of water only with known tubing by inner annulus communication. This replacement administrative approval clarifies the requirements for continued injection using PBU W-42. By electronic mail dated November 13, 2015, BP Exploration (Alaska) Inc. (BPXA) requested approval to conduct the required mechanical integrity test (MIT) of the inner annulus to a test pressure of 1400 psi. According to BPXA, results of a 2013 caliper survey indicate the well's tubing has corrosion and mechanical damage with a maximum recorded pipe wall penetration of 72 percent. By email dated November 19, 2015, BPXA deemed PBU W-42 inoperable and shut the well in due to surface equipment issues. AOGCC review of the request to test to a lower pressure was suspended at that time. Surface equipment issues were resolved in July 2016 at which time BPXA returned the well to injection and performed a 1400 psi test. AOGCC regulation at 20 AAC 25.412 establishes the minimum pressure for a required mechanical integrity test to be 1500 psi. BPXA notes that Administrative Approval AIO 3.026 — as corrected May 8, 2009 — requires testing to the maximum anticipated injection pressure. According to BPXA's November 13, 2015 email, historic records indicate the maximum injection pressure has been approximately 1200 psi. The requirements included in AIO 3.026 by AOGCC were not intended to establish a test pressure that contradicts the requirements in 20 AAC 25.412. The mechanical integrity limitations and BPXA's intent to test to a lower test pressure were not evident to AOGCC until November 2015. AIO 3B.004 August 16, 2016 Page 2 of 2 The AOGCC finds that the well's deteriorating condition represents concern for continued injection into PBU W-42. BPXA is encouraged to initiate repairs to restore the well's tubing integrity. AOGCC also finds that BPXA has misinterpreted the requirements of AIO 3.026 by testing the inner annulus to 1400 psi on July 31, 2016. The conditions of this replacement administrative approval are as follows: 1. BPXA is authorized to inject water only; 2. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Pressure bleeds are to be flagged on the report; 3. BPXA shall perform a MIT of the tubing -casing annulus (MITIA) each July to 1500 psi; 4. BPXA shall limit the well's outer annulus pressure to 500 psi; the inner annulus pressure shall be limited to 1500 psi; 5. BPXA shall perform a caliper survey of the tubing annually beginning no later than September 30, 2016. Interpreted results, including any calculations that are used as a basis for derating the well's tubing and casing, shall be provided to AOGCC within 30 days after completing the caliper survey; 6. This administrative approval expires if pressure monitoring, tests or surveys show further deterioration of the well's mechanical integrity, and not later than December 31, 2018. DONE at Anchorage, Alaska and dated August 16, 2016. OIL 4CatP. Foerster Daniel T. Se ount, Jr. Hollis S. French Al Chair Commissioner Commissioner Commissioner ��F � +?p9T�U COMA RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Tuesday, August 16, 2016 11:10 AM To: Ballantine, Tab A (LAW) (tab.ballantine@alaska.gov); Bender, Makana K (DOA) (makana.bender@alaska.gov); Bettis, Patricia K (DOA) (patricia.bettis@alaska.gov); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA) oody.colombie@alaska.gov); Cook, Guy D (DOA); Davies, Stephen F (DOA) (steve.davies@alaska.gov); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA) (cathy.foerster@alaska.gov); French, Hollis (DOA); Frystacky, Michal (michal.frystacky@alaska.gov); Grimaldi, Louis R (DOA) (lou.grimaldi@alaska.gov); Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA) (Jeff jones@alaska.gov); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored) ooseph.mumm@alaska.gov); Noble, Robert C (DOA) (bob.noble@alaska.gov); Paladijczuk, Tracie L (DOA) (tracie.paladijczuk@alaska.gov); Pasqual, Maria (DOA) (maria.pasqual@alaska.gov); Quick, Michael (DOA sponsored); Regg, James B (DOA) Oim.regg@alaska.gov); Roby, David S (DOA) (dave.roby@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); Singh, Angela K (DOA) (angela.singh@alaska.gov); Wallace, Chris D (DOA) (chris.waIlace@alaska.gov); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; Becky Bohrer; Bill Bredar; Bob; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; Dean Gallegos; DNROG Units; Donna Ambruz, Ed Jones; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; gspfoff, Hyun, lames J (DNR); Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Joe Nicks; John Burdick; John Easton; Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Laura Silliphant (laura.gregersen@alaska.gov); Leslie Smith; Louisiana Cutler; Luke Keller, Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Marquerite kremer (meg.kremer@alaska.gov); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); nelson; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Paul Decker (paul.decker@alaska.gov); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Rena Delbridge; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); Steve Quinn; Suzanne Gibson; Tamera Sheffield; Ted Kramer; Temple Davidson; Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vicki Irwin; Vinnie Catalano; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline 1; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Eric Lidji; Garrett Haag; Graham Smith; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W To: (DNR); Marc Kuck; Marcia Hobson; Marie Steele; Matt Armstrong; Mike Franger; Morgan, Kirk A (DNR); Pascal Umekwe; Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Susan Pollard; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Area Injection Order 36.004 (PBU, BPXA) Attachments: aio3B-004.pdf On its own initiative, the Alaska Oil and Gas Conservation Commission (AOGCC) RESCINDS and REPLACES Administrative Approval AIO 3.026 which allows Prudhoe Bay Unit W-42 (PBU W-42) to continue injection of water only with known tubing by inner annulus communication. This replacement administrative approval clarifies the requirements for continued injection using PBU W-42. Samantha Carlisle 1 �r�t.ttf�v€3 �?exc're�ta�ry 1I.I Irr'i"t t fl arrci Gas ("'.onservt'Ition Anl'tc)t.r)jc=, r l°5 `)� 501 (910/) 79 3-1223 CONFII7F..NFIALITY NOTICE: This e-mail message, including any attachments, contains information frorn the Alaska Oil and. Gas Conservation Commission (.AOGCC), State of Alaska and is .for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please: delete it, withoot first saving or forwarding it, and, so that the AOGCC is aware of the mistake in. sending .it to you, contact Samantha Carlisle at (907) 793-1223 or Sa.mantha.Carlisleci7,alaska.ggy. Box 190083 Bernie Karl P.O. Box Jack a K&K Recycling Inc. P.O. Box 58055 Anchorage, AK 99519 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.005 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-16-039 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Request for administrative approval to allow well P-06B (PTD 2101010) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) P-06B (PTD 2051380) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated September 7, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 27, 2016 which indicates that P-06B exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 180 psi/day while on gas service. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AIO 3B.005 September 30, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU P-06B is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC appry vial shall be required to restart injection; and got 7. The MIT anniversary date is May 27, 2016. DONE at Anchorage, Alaska and dated September 30, 2016. Cathy k. Foerster Chair, Commissioner le�p� Daniel T. Seamount, Jr. Commissioner RECONSIDERATION AND APPEAL Hollis French 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 flee 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, September 30, 2016 1:59 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator; Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vandedack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck, Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: Aio3B-005 (BPXA) Attachments: aio3B.005.pdf Please see attached. Disregard Administrative Order previously sent today! Re: Docket Number: AIO-16-039 Request for administrative approval to allow well P-06B (PTD 2101010) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) P-06B (PTD 2051380) Prudhoe Bay Field Prudhoe Oil Pool lody J. Colom6ie AO(�C(' silecial,Assistal7t Alaska Oil aiut_(yas Conset-vation Comvyiission Il7esi 7"' _AJ1e)7t1e Anchorage, .Alaska g�)5o1 OBice: (�)07) 793-1221 'az: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or jodv.colombie@alaska.aov. Jack Hakkila Bernie Karl P.O. Box 190083 K&K Recycling Inc. Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission AMENDED ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.005 Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: Docket Number: AIO-16-039 Request for administrative approval to allow well P-06B (PTD 2051380) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) P-06B (PTD 2051380) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated September 7, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported a potential Inner Annulus repressurization to AOGCC and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on May 27, 2016 which indicates that P-06B exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 180 psi/day while on gas service. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AIO 3B.005 September 30, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU P-06B is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is May 27, 2016. DONE at Anchorage, Alaska and dated September 30, 2016. //signature on file// //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Hollis French Chair, Commissioner Commissioner Commissioner TION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, October 05, 201611:11 AM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator; Alan Bailey, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack, Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gregg Nady; Gretchen Stoddard; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jerry McCutcheon; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; Sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: AIO 3B-005 Amended Attachments: aio3B.005.pdf Please see attached. The previously emailed Administrative Approval had the wrong permit to drill number apologize for any inconvenience this may have caused. Re: Docket Number: AIO-16-039 Request for administrative approval to allow well P-06B (PTD 2051380) to be online in water only injection service with known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) P-06B (PTD 2051380) Prudhoe Bay Field Prudhoe Oil Pool Jody. Coto IIIhie AO(jCC Special .Assistant .Alaska oilanci(�as Co1lservation Commission 333 0"est ; " .'Avenue _Allciiorage, -Alaska �)g5oi 01ICe: (�)07) 793-1221 _'ax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. Box 190083 Bernie Karl P.O. Box Jack a K&K Recycling Inc. P.O. Box 58055 Anchorage, AK 99519 Fairbanks, AK 99711 Penny Vadla George Vaught, Jr. 399 W. Riverview Ave. P.O. Box 13557 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Well Integrity Engineering Team Leader P.O. Box 60868 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 P.O. Box 196612 Anchorage, AK 99519-6612 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 oit ��8- �C) — 5 — \c.,t. c�Nlc THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.006 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Docket Number: AIO-17-004 Request for administrative approval to allow well Z-19A (PTD 2061050) to be online in water alternating gas (WAG) injection service with an outer annulus (OA) repressurization. Prudhoe Bay Unit (PBU) Z-19A (PTD 2061050) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter dated February 2, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. Injection into PBU Z-19A will be governed by provisions of this approval and AIO 3B. AIO No. 3A superseded AIO 3 on August 23, 2011. AIO No. 3B superseded AIO 3A on October 15, 2015. BPXA operated this well under AIO 3.017 from May 2007 to December 2011 with an OA repressurization. The well was shut in and the AA was cancelled when BPXA determined the well could no longer be managed by bleeds. BPXA now indicates the OA pressure stabilizes between 900 and 1100 psi. BPXA has completed an engineering analysis and determined the well can be safely operated with an OA operating pressure limit of 1500 psi. BPXA will complete a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that Z-19A exhibits at least two competent barriers to the release of well pressure. AIO 3B.006 February 14, 2017 Page 2 of 2 Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AOGCC's approval to continue WAG injection in PBU Z-19A is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall limit the well's inner annulus operating pressure to 2000 psi and the outer annulus operating pressure to 1500 psi; 4. BPXA shall perform a mechanical integrity test of the inner annulus every two (2) years to 1.2 times the maximum anticipated injection pressure; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition. This could be indicated by inner or outer annulus pressure, increased repressure rate, or increased bleed frequency; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity establish the new MIT anniversary date. to witness the MIT for the test that will DONE at Anchorage, Alaska and dated February 14, 2017. v )01 Cathy . F erster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner TION AND APPEAL NOTICE Hollis French 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. T*l it STAT ALASKA Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.006 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-004 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Request for administrative approval to allow well Z-19A (PTD 2061050) to be online in water alternating gas (WAG) injection service with an outer annulus (OA) repressurization. Prudhoe Bay Unit (PBU) Z-19A (PTD 2061050) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter dated February 2, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 3B.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. Injection into PBU Z-19A will be governed by provisions of this approval and AIO 3B. AIO No. 3A superseded AIO 3 on August 23, 2011. AID No. 3B superseded AIO 3A on October 15, 2015. BPXA operated this well under AID 3.017 from May 2007 to December 2011 with an OA repressurization. The well was shut in and the AA was cancelled when BPXA determined the well could no longer be managed by bleeds. BPXA now indicates the OA pressure stabilizes between 900 and 1100 psi. BPXA has completed an engineering analysis and determined the well can be safely operated with an OA operating pressure limit of 1500 psi. BPXA will complete a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that Z-19A exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 3B.006 February 14, 2017 Page 2 of 2 AOGCC's approval to continue WAG injection in PBU Z-19A is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall limit the well's inner annulus operating pressure to 2000 psi and the outer annulus operating pressure to 1500 psi; 4. BPXA shall perform a mechanical integrity test of the inner annulus every two (2) years to 1.2 times the maximum anticipated injection pressure; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition. This could be indicated by inner or outer annulus 2 VA pressure, increased repressure rate, or increased bleed frequency; After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated February 14, 2017. //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. (''hair Cnmmk6nnPr CnmmtSsinner AND APPEAL //signature on file// Hollis French 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 he 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Tuesday, February 14, 2017 3:22 PM To: DOA AOGCC Prudhoe Bay, Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqua[, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock, Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy, David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oar[ington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity, Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: aio3b-006 (BPXA) Attachments: aio3B.006.pdf Re: Docket Number: AI0-17-004 Request for administrative approval to allow well Z-19A (PTD 2061050) to be online in water alternating gas (WAG) injection service with an outer annulus (OA) repressurization. Prudhoe Bay Unit (PBU) Z-19A (PTD 2061050) Prudhoe Bay Field Prudhoe Oil Pool Jody J. Cotom6ie _AO(iCC Special -Assistant .Alaska 0it-and (jas Cooser-vation Commission 333 West 7"' .Avenue Anchorago, .Alaska o,)5oi ORi('e: (907) 793-1221 .FaX: (()07) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 rn�le� THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.007 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-007 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.claska.gov Request for administrative approval to allow well R-02 (PTD 1781000) to be online in water only injection service with a known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R-02 (PTD 1781000) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter dated February 9, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA completed a cement packer squeeze in November 2016 to alleviate a tubing x IA pressure communication. BPXA completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 20, 2016 which indicates that R-02 exhibits at least two competent barriers to the release of well pressure. BPXA reported a potential Inner Annulus repressurization to AOGCC in early January 2017 and initiated additional diagnostics and monitoring. The well has a recorded IA build up rate of 67 psi/day while on water service. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AIO 3B.007 February 15, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in PBU R-02 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi, and the well's OA operating 5 n 7. pressure to 1000 psi; BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; After well shut in due to a change in the well's mechanica. shall be required to restart injection; and The MIT anniversary date is December 20, 2016. DONE at Anchorage, Alaska and dated February 15, 2017. CaThy Y. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE 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. `I'I II; S"I'A'1'1 °'ALASKA Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.3B.007 Mr. Aras Worthington Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-17-007 Request for administrative approval to allow well R-02 (PTD 1781000) to be online in water only injection service with a known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R-02 (PTD 1781000) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Worthington: By letter dated February 9, 2017, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 3B.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA completed a cement packer squeeze in November 2016 to alleviate a tubing x IA pressure communication. BPXA completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 20, 2016 which indicates that R-02 exhibits at least two competent barriers to the release of well pressure. BPXA reported a potential Inner Annulus repressurization to AOGCC in early January 2017 and initiated additional diagnostics and monitoring. The well has a recorded IA build up rate of 67 psi/day while on water service. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment AIO 3B.007 February 15, 2017 Page 2 of 2 AOGCC's approval to continue water injection only in PBU R-02 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi, and the well's OA operating pressure to 1000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is December 20, 2016. DONE at Anchorage, Alaska and dated February 15, 2017. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr. Commissioner //signature on file// Hollis French 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 he 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, February 15, 2017 1:29 PM To: DOA AOGCC Prudhoe Bay, Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Darci Horner; Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty, Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler, Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer, Teresa Imm; Thor Cutler, Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity, Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: aio2b-007 (BPXA) PBU R-02 Attachments: aio3B.007.pdf Re: Docket Number: AI0-17-007 Request for administrative approval to allow well R-02 (PTD 1781000) to be online in water only injection service with a known inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) R-02 (PTD 1781000) Prudhoe Bay Field Prudhoe Oil Pool Jody 1. Cotorm6ie AO( ('(' Special Assistant Alaska Oitand (aas Conservation Commission 333 West 7"' Avenue anchorage, Alaska 99.50� Office: (907) 793-1221 f'a x: (9 07) 276-754 z CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE °fALASKA GOVERNOR BILL WALKER ADMINISTRATIVE APPROVAL AREA INJECTION ORDER 311.008 Mr. Ryan Daniel Well Integrity Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-18-012 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fox: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well S-1113 (PTD 1990530) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) S-1 IB (PTD 1990530) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated February 26, 2018, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 3B.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue water only injection in the subject well. BPXA reported to AOGCC a potential inner annulus by outer annulus pressure communication in October 2017 and initiated additional diagnostics and monitoring. BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 31, 2017. BPXA will complete a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) once the well returns to injection and after stabilization is achieved. A passing MITIA will confirm that S -I IB exhibits at least two competent barriers to the release of well pressure. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. A[0 3B.008 March 6, 2018 Page 2 of 2 AOGCC's approval to continue water injection only in PBU S -IIB is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi and the OA operating 5. 0 pressure to 1000 psi; BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The MIT anniversary date will be set as the date of the AOGCC witnessed MITIA that is to be completed once the well is returned to injection and stabilization is achieved. AOGCC must be provided the opportunity to witness the MIT for the test that will establish the new MIT anniversary date. DONE at Anchorage, Alaska and dated March 6, 2018. Hollis French Chair, Commissioner Daniel T. Seamount, Jr. Commissioner AND APPEAL 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 w 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. Colombie, Jody 1 (DOA) From: Colombie, Jody 1 (DOA) Sent: Tuesday, March 06, 2018 10:50 AM To: DOA AOGCC Prudhoe Bay, Bender, Makana K (DOA sponsored); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mcphee, Megan S (DOA); Rixse, Melvin G (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWeIIIntegrityCoordinator, Alan Bailey, Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Bonnie Bailey, Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner, Dave Harbour, David Boelens; David Duffy, David House; David McCaleb; ddonkel@cfl.rr.com; Diemer, Kenneth 1 (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Chmielowski, Josef (DNR); Joshua Stephen; Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin 1 (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz, knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky, NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly, Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney, trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity, Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Casey Sullivan; Corey Munk; D. McCraine; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: Admin Approval AIO 38.008 Attachments: aio3B.008.pdf Please see attached. Docket Number: A10-1 8-012 Request for administrative approval to allow well S-1 IB (PTD 1990530) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Prudhoe Bay Unit (PBU) S -11B (PTD 1990530) Jody J. Cotombie .AOGCC Speeia(Assistant ,Alaska OilandGas Conservation Commission 333 -Nest 711 .Avenue Anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 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). If may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie®alaska.aov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 THE STATE Alaska Oil and Gas °fALASKA Conservation Commission 333 West Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501 Main: 907.297.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 311.009 Mr. Ryan Daniel Well Integrity Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-18-042 Request for administrative approval to allow well V-05 (PTD 2080930) to be online in water alternating gas (WAG) injection service with an inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) V-05 (PTD 2080930) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated November 12, 2018, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported to AOGCC a potential inner annulus repressurization in February 2018 and initiated additional diagnostics and monitoring. BPXA completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 19, 2018 which indicates that V-05 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 40 psi/day and a stabilized IA pressure of 1250 psi. BPXA has replaced the dummy gas lift valves to mitigate the IA repressurization and installed wireless gages on V -pad wells that allow for real time monitoring and alarm notifications of IA and outer annulus (OA) pressures. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 38.009 November 14, 2018 Page 2 of 2 AOGCC's approval to continue WAG injection in PBU V-05 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is March 19, 2018. DONE at Anchorage, Alaska and dated November 14, 2018. Hollis French Chair, Commissioner N P4 Cathy P. Foerster 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 oil 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. FI 11: STATY ,ALASKA (,0VERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 3B.009 Mr. Ryan Daniel Well Integrity Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 aogcc.alaska.gov Re: Docket Number: AIO- 18-042 Request for administrative approval to allow well V-05 (PTD 2080930) to be online in water alternating gas (WAG) injection service with an inner annulus (IA) repressurization. Prudhoe Bay Unit (PBU) V-05 (PTD 2080930) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated November 12, 2018, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 313.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request for administrative approval to continue WAG injection in the subject well. BPXA reported to AOGCC a potential inner annulus repressurization in February 2018 and initiated additional diagnostics and monitoring. BPXA completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 19, 2018 which indicates that V-05 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 40 psi/day and a stabilized IA pressure of 1250 psi. BPXA has replaced the dummy gas lift valves to mitigate the IA repressurization and installed wireless gages on V -pad wells that allow for real time monitoring and alarm notifications of IA and outer annulus (OA) pressures. AOGCC finds that BPXA is able to manage the IA pressure with periodic pressure bleeds. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 3B.009 November 14, 2018 Page 2 of 2 AOGCC's approval to continue WAG injection in PBU V-05 is conditioned upon the following: 1. BPXA shall record wellhead pressures and injection rate daily; 2. BPXA shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. BPXA shall perform a mechanical integrity test of the inner annulus (MITIA) every 2 years to the maximum anticipated injection pressure; 4. BPXA shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The MIT anniversary date is March 19, 2018. DONE at Anchorage, Alaska and dated November 14, 2018. //signature on file// Hollis French Chair, Commissioner //signature on file// Cathy P. Foerster 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 dues not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 • Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 THE STATE °fALASKA Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 3B.002 CANCELLATION Mr. Stan Golis PBW Operations Manager Hilcorp North Slope, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Docket Number:AIO-21-017 Request to cancel Area Injection Order No. 3B.002 Prudhoe Bay Unit S-41A (PTD 210101), Prudhoe Oil Pool Dear Mr. Golis: By letter dated June 29, 2021, Hilcorp North Slope, LLC (Hilcorp) requested cancellation of administrative approval of Area Injection Order (AIO) 313.002. In accordance with Rule 10 of AIO 3C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS Hilcorp's request to cancel the AIO 3B.002. On January 22, 2015, then -operator BP Exploration (Alaska), Inc. (BPXA) reported to AOGCC a potential inner annulus (IA) repressurization while the well was injecting gas. On August 2, 2016, AOGCC issued AIO 3B.002. AOGCC determined that water only injection could safely continue if BPXA, now Hilcorp, complied with the restrictive conditions set out in the administrative approval of AIO 3B.002. AIO 3B.002 remained in effect when AIO 313.000 was revoked and replaced by AIO 3C.000 on April 3, 2019. On March 6, 2021, Hilcorp repaired the well. Hilcorp monitored the well for 60 days and the gas injection shows no indications of IA repressurization. Therefore, the administrative approval of AIO 3B.002 is no longer necessary to the operation of S-41A and is hereby CANCELLED. DONE at Anchorage, Alaska, and dated July 6, 2021. Jeremy D'g"'b Price D•rc,ma.w.oa ,7953 W Jeremy M. Price Chair, Commissioner Dan Digital, Agre MDnn 5 moum Seamount Da.:2021 '07 '06 Daniel T. Seamount, Jr. Commissioner A10 3B.002 July 6, 2021 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the 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 ran 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. Salazar, Grace (CED) From: Salazar, Grace (CED) Sent: Tuesday, July 6, 2021 5:39 PM To: AOGCC Public Notices Subject: AOGCC Area Injection Order 36.002 (Cancellation) Attachments: AIO 36.002 Cancel lation.pdf Please see attached. Re: Docket Number: AIO-21-017 Request to cancel Area Injection Order No. 3B.002 Prudhoe Bay Unit S-41A (PTD 210101), Prudhoe Oil Pool Respectfully, M. Grace Salazar, Special Assistant Alaska Oil and Gas Conservation Commission 333 West 71^ Avenue Anchorage, AK 99501 Direct: (907) 793-1221 Email: grace.salazar@alaska.gov https://www.commerce.alaska.gov/web/aogcc/ 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. P.O. Box 13557 Denver, CO 80201-3557 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 INDEXES 20 Hilcorp North Slope, LLC Stan Golis, PBW Operations Manager 3800 Genterpoint Or, Suite 1400 Anchorage, Alaska 99503 RECEIVED 06/29/2021 By Grace Salazar at 2:10 pm, Jun 29, 2021 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 711 Avenue Anchorage, Alaska 99501 Subject: Prudhoe Well S-41A (PTD4 210101) Request for Cancelation of AIO No. 313.002 Dear Mr. Price, Hilcorp North Slope, LLC requests cancelation of AIO No. 3B.002 for well S-41A dated 08102/2016. The administrative approval was for continued water injection service with known inner annulus (IA) repressurization. On 03/06/2021 work was completed to load the IA of S-41A with 9.8 ppg brine and replace the dummy gas lift valves. S-41A was then placed on MI for a 60 day under evaluation period with permission from the AOGCC beginning 05/04/2021. Over the course of the evaluation period no IA repressurization has been seen indicating that the repair was successful, therefore the cancelation of AID No. 3B.002 is requested. If you have any questions, please call me at 907-564-5231 or Ryan Holt/ Andy Ogg at 659- 5102. �Sincerely, Stan Golis PBW Operations Manager Attachments TIO/ Injection Plot Wellbore Schematic 4, 1 r _��8 2 F f�!�lw� Vl 0 O FL c O U N .L s ff I.. Wellbore Schematic TREE- 4-INB•CIW Y Lr LIEAD FM ACitATOR• BAKER OM ELEV • 112' REF ELEV• NJN' BF ELEV - 3r KW • 1131' NV Ary*- N•®14BL1' N3- 11043. IDW D4 TVD- 000C BB I�►6O•C8O.401, 1a08O1'T, 10. 01]s' 3332' r 1,SC., 21r, l4D BTC .0]&10p1, D-0270' 4 113Tlr Minimum D = 3.726' @ 11916' 4-112" HES XN NIPPLE YLLOV7W DOW(L41L1711M0. 110N' BOIEEM OFF 00O7N0 IUFPTAG H117R' 4-77I TBG12.SN. 13CR05 VAAITOP, H 11961' IOPCF s-+2•lM 119w r C9G. 2OL L w B1oA1 .0A1 Oq, D=6.101• -12017' FE MA71GN9.041A Y FIEF LOO SLJT OVAY04 OIOIN21110 AN3 EATTOPFEi: W' O n Mo. Rofw lo NOOwcbm CU iw 1w1011001 pBN OW SIZE SF I WTE7VAL I QnSW DATE S-41A 2JAr 6 12700.13100 O 100OW10 2JAr 6 13MO-13WO O 1onw10 2-Tff 6 13700-14100 O 1009110 2-71W 6 142OD-M350 O 10D&10 2.7fir 0 149V 15150 O 100WID 9.41AL7 4-V.r SLTD 11947-11992 SLOT 1O'70/10 4-10 SLM 123D1 - 136% SLOT 10110N0 BAfEfY NDT� L ANGLE>TO' Q 120N"" 4.11r S -41 A 1 19 V=M GAS LFT AMMS ST LD TVD OEV TYPE VLV LT01 FORE DATE 5 3742 3331 40 I®G-Y OMY 6K 0 03DV14 4 7112 5508 K3G-2 MY Y BK 0 OWY14 3 9705 7M5 47 KB&2 OW OK 0 031O3114 2 11839 am: 85 10r,2 ••OFT BK D 03*Ml 1 i1B0B 8818 i 1 64 1 K0o2 '01Y OK 0 0613,11 • RA h glOW P10.111ABLE 7OIREPOR a -ilk -Irr NEB xD DIATO BLD Bw,1D-3si3•— OPENOY02G1 l0MWIDOW(S-41AL1) 11BM 1193W 11Mr WMHANGLC LOTT®LB6t S•41AL1 4-V7SLTDlNA12.B4,L.800B 13701' .0152 L;L D.3.B58' SFFT_ mE 16i6r MLLOOTVVIDDWJ"A) 720D'-1201r LUTE iREV BY COM.ENIS DATE REVBYt COMMENTS FRDIDESAYLM V*E S41A/ALl PERNTM: 2101010(20) MI W. 5042922645401(61) SEC35,T12KR12E,11MFN-1r25'FWL �l 101E :0F06LYL C0IPLETON 177M5 RCTOADIGYCD 11N7N5 t0ON10 0O75M7 FOES i1ME1RALK0141NAL1) MVPJC jRf AL DRLG ODRRECTKM OR25MG N_VRJLD:CLOSm SIDSLV (0O17A8) GV10O1_ JPK•CF 'GiV CD(03OB121) OBRSN7 ALW PJC�CiY CA 16'13111) ALNPJC PLLL PA PLUG(O6HYi11 RKrOADOLV 0O — 4 060321 _TBDI D:6NFTEDDNKi SIDSLVOPEN 05N4Q1 AB/JLO ADDED ELEV —__ _ 08N6'I7 OMM4 FOkOry Norlh SFOpe. LLC 19 by BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineering Team Lead Post Office Box 196612 Anchorage, Alaska 99519-6612 0 December 08, 2019 Mr. Jeremy Price, Chair Alaska Oil and Gas Conservation Commission 333 West 7«' Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well R-02 (PTD # 2191120) Request for Cancellation of Administrative Approval NO 3B.007 Dear Mr. Price, BP Exploration (Alaska) Inc. requests cancellation of Administrative Approval NO 3B.007. The approval, originally issued February 15, 2017, was for water only injection with known inner annulus repressurization. The well recently had a rig work over which was completed on 07/17/2019 repairing the inner annulus repressurization. A Coil Drilling Sidetrack was also completed on 11/17/19. If you have any questions, please call me at 907-564-5430 or Ryan Holt at 659-5102. Sincerely, Ryan Daniel BPXA Well Integrity Engineering Team Lead RECEIVED DEC 10 2019 AOCCC BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineering Team Lead Post Office Box 196612 Anchorage, Alaska 99519-6612 November 12. 2018 by 0 RECEIVE® Hollis French, Chair NOV 13 2018 Alaska Oil and Gas Conservation Commission 333 West 71^ Avenue (QCili�i Anchorage, Alaska 99501 Subject: Prudhoe Bay Well V-05 (PTD #2080930) Request for an Administrative Approval for WAG Injection Operations Dear Mr. French, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for water alternating gas (WAG) injection into Prudhoe Bay well V-05. No change to normal operating limit (NOL — formerly MOASP) is required. V-05 was identified to have anomalous IA repressurization in February 2018. At that time, the repressurization rate was 175 psi/day and stabilized at 1,250 psi. In preparation for the administrative approval request, an AOGCC witnessed MIT -IA was performed on 03/19/18 and passed to 3,421 psi. BPXA have replaced the existing dummy gas lift valves with extended packing dummy gas lift valves, to mitigate the IA repressurization. This slowed the repressurization rate to 40 psi/day over the test period, 09/16-11/05 2018 Wireless gauges have been installed on V -Pad wells that allow for real time monitoring and alarm notification of IA and OA pressures. BPXA has determined that well V-05 is safe to operate in its current condition and requests an AA for WAG (including MI) injection based on the following: • IA pressure stabilizes below NOL and should not require bleeds during normal operation. • MIT -IA passed to 1.1 times maximum anticipated injection pressure. • IA and OA pressures will be monitored with wireless pressure gauges. If you have any questions, please call me at 907-564-5430 or Jack Lau/Adrienne McVey at 659- 5102. Sincerely, Ryan Daniel BPXA Well Integrity Engineering Team Lead ORIGINAL Attachments Technical Justification TIO Plot Injection Plot Wireless Gauge Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey GC2 Operations Team Leader Cale Peru Ryan Daniel Oliver Sternicki Beau Obrigewitch Prudhoe Bay Well V-05 Technical Justification for Administrative Approval Request November 5, 2018 Well History and Status Well V-05 was drilled and completed in October 2008 as a long horizontal well in Upper Zone 4 with the original objective of converting the well to WAG injection once it became uncompetitive to produce. As a producer, a leaking packer was discovered and fixed with a cement squeeze in 2010. The well was converted to an injector in 2012 per Sundry 312-128 and was re-classified as a WAG injector in 2015 per Sundry 315-674. It has been on miscible gas injection since April of 2017. IA repressurization occurred in February of 2018. Recent Well Events: > 7/1/2018 MIT -IA Passed to 2675 psi, Pulled TTP >6/29/2018 TTP set @ 10,189' MD > 3/19/2018 AOGCC MIT -IA Passed to 3421 psi (Pre AA application) > 2/22/2018 MIT -IA Passed to 3408 psi > 2/16/2018 PPPOT-T/IC Passed >4/23/2017 Caliper (10,851' to surface) > 3/29/2017 AOGCC MIT -IA Passed to 2359 psi > 12/9/2015 Reclassified back to WAG injector per Sundry 315-674 > 10/17/2015 MIT -IA Passed to 4000 psi after GLV c/o > 9/30/2015 PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3500 psi > 3/31/2013 AOGCC MIT- IA Passed to 2512 psi > 3/8/2013 Reclassified as Water Injector Only for failing internal BP MIT -IA per 10- 404 Sundry #2080930 > 2/10/2013 MIT -IA Passed to 2500 psi > 1/27/2013 PPPOT-T Passed > 1/21/2013 BP internal MIT -IA Failed to 3500 psi, MIT -IA Passed to 3000 psi > 1/7/2013 MIT -IA Passed to 4000 psi > 1/1/2013 PPPOT-IC Passed > 12/9/2012 AOGCC MIT -IA Failed (C. Scheve) to 4000 psi > 8/13/2012 MIT -IA Passed to 2500 psi > 8/12/2012 MIT -IA Failed to 2500 psi > 8/11/2012 DGLVs > 4/17/2012 Converted from Producer to WAG injector under Sundry 312-128 Barrier and Hazard Evaluation The primary and secondary barrier systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 3,421 psi, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is online. Proposed Operating and Monitoring Plan 1. WAG injection (including MI). 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to 1.1 x maximum anticipated injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 11N119UP The range on the left show T/I/O Pressures during the previous injection period, 01/12-03/20 The range on the right show T/I/O Pressures during the trial period, 09/16-11/05. This data is read and entered daily by the Pad Operator. For comparison, this same date range is displayed in the graph "Wireless Gauge TIO Plot". Prior to the trial period, all Dummy Gas Lift Valves were changed out for valves with extended packing. TIO Plot —49— Tbg ■ IA SOA OOA ♦ OOOA On ■ Ble < Operable i Not Oper thoho E.1 Tton,00 mre Injection Plot wm V� The range on the left shows Injection Pressure and Rate during the previous injection period, 01/12-03/20 The range on the right shows Injection Pressure and Rate during the trial period, 09/16- 11/05 — NHIP SW — RV — MI —GI — Giha — o� Wireless Gauge TIO Plot 0 Well V-05 was put on MI Injection Under Evaluation on 09/16/2018 and shut-in and made Not Operable on 11/05/2018. The date range of this plot in 09/15/2018 through 11/06/2018. The annular pressure data displayed here is transmitted and recorded real- time via wireless gauges. ACRATOR= 10675-10720 103. FLIM = - 6 BF. ELiV - O KOP= 11450 -11474 My Angle = 106' @ 1 Mt mM1= 1 Minimum ID = 2.726" A 1018W HES XN NIPPLE F73FOPATIONSIMMRI LS LOG: SWS VUON ON 10113108 ANGLEATTOPFEAP: 44m®1057T 4 10675-10720 O 6 10720-10730 O 6 11450 -11474 O 6 11489-11UM O 4 11524 - 11594 O 4 116107 - 1169 O 4 11670-11700 O 4 11711 - 119M 0 4 12180 - 12310 O V-05 SAFETY NOTES: WELL ANGLE>70° 0 10855'- STA a1=COVEIEDUY CMT 10717' ,�7':5"RKRHRn7XPITPKR. -v. _ wA3KRHMCLN2HGRD=4., P9TD I-1 12877' -M(r 16 ®r L -6V r CI -Al V l ]L OFi. V m 3 -JiT RSHTO 2204' 4-17 HF5XnP,D+J.B73' DITP PPV BY I COIMSBS I DATE REV BY I COMMMS GAS LFT MA MORE -S 0712WI1 MW PJC LOG Rff LOO UPDATE ST NO TVD OEV TYFE VLV LATCH FOF { 3623 3212 45 KEIG2 DMY BK 0 3 W24 5419 30 KBG2 DW 6K 0 2 6129 7061 29 K8G2 DMY BK 0 -1 10097 8498 32 Kt3G2 OW SK 0 STA a1=COVEIEDUY CMT 10717' ,�7':5"RKRHRn7XPITPKR. -v. _ wA3KRHMCLN2HGRD=4., P9TD I-1 12877' -M(r 16 ®r L -6V r CI -Al V l ]L OFi. V m 3 -JiT RSHTO FFIIIHOE BAY LW 1M3 -L V-05 Pew W. 20OW30 MW: 50-02323391-00 SFC 11, T11N R11E 649' FW 1861' FTi DITP PPV BY I COIMSBS I DATE REV BY I COMMMS 10118108 NDM ORG NOIR COMPLETION ".07126118 CJNAU GLVOO(061301181 0712WI1 MW PJC LOG Rff LOO UPDATE 04W12 RIC PEW O0FaEcilON 08115112 FCVJkD GLV M (08111/12) 11/O.T115 JLSIJBO GLV CIO(10/16MM ' FP "s aticn (Almka) 04NW18 M VJND F9RS 70 M CMF 8 STA 81 GLV m THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.a ogcc.a laska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 3B.007 CANCELLATION Mr. Ryan Daniel Well Integrity Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-19-037 Request to cancel Area Injection Order (AIO) 3B.007 Prudhoe Bay Unit (PBU) R-02 (PTD 178 1000) R -02A (PTD 2191120) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated December 8, 2019 BP Exploration (Alaska), Inc. (BPXA) requested cancellation of administrative approval (AA) Area Injection Order 3B.007. In accordance with Rule 10 of Area Injection Order (AIO) 3B.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request to cancel the AA. R-02 developed an inner annulus repressurization in January 2017 and on February 15, 2017 the AOGCC issued AIO 3B.007. AOGCC determined that water only injection could safely continue if BPXA complied with the restrictive conditions set out in AA AIO 3B.007. BPXA replaced the production tubing of R-02 under Sundry 319-081 but then abandoned R-02 prior to drilling a new coiled tubing sidetrack R -02A (PTD 291120) completed on November 17, 2019. The R -02A well completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 8, 2019 which indicates that R -02A exhibits at least two competent barriers to the release of well pressure. AA AIO 3B.007 is no longer necessary to the operation of R -02A and is hereby CANCELLED. ATO 313.007 Cancellation December 11, 2019 Page 2 of 2 DONE at Andorage, Alaska and dated December 11, 2019. Price Daniel T. Seamount, Jr. J6ie L. Chmielowski Chair, Commissioner Commissioner Commissioner RECONSIDERATION AND APPEAL 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 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 17 RECEIVED bp BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Team Leader Post Office Box 196612 FEB 2 6 2018 Anchorage, Alaska 99519-6612 AOGGG 0 February 26, 2018 Mr. Hollis French Alaska Oil and Gas Conservation Commission 333 West 7' Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well S-11 B (PTD # 1990530) Request for Administrative Approval for continued water Injection Operations Dear Mr. French, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for continued water injection into Prudhoe Bay Well S-11 B. The well exhibits slow inner annulus by outer annulus communication when shut in. The well passed a non -witnessed AOGCC MIT -IA to 3,000 psi on 10/31/2017, indicating the tubing and production casing are competent barriers. In summary, BPXA has determined that Prudhoe Bay Well S-11 B is safe to operate as stated above and requests Administrative Approval for continued water injection operations. If you have any questions, please call me at 564-5430 or Jack Lau/ Adrienne McVey at 659- 5102. Sincerely, 1� Ryan Daniel BPXA Well Integrity TL Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic 10-426 Form — MIT -IA Pressure Test Data 10/31/17 Cc: Louis Romo Lau/McVey GC2 Operations Team Leader Lea Duong Ryan Daniel Prudhoe Bay Well S -11B Technical Justification for Administrative Approval Request February 26, 2018 Well History and Status Well S-11 was initially drilled in June 1982. In August 1999, a rotary sidetrack was completed to relocate the injection interval. The well developed IA x OA communication through a leak at 2,604' in November 2007. The tubing was punched to enable access to the IA to repair the IA x OA communication with a Seal-tite treatment on 7/5/2008. A patch was set in the tubing to repair the TxIA caused by the tubing punches. The well injected produced water until October 2016. On 8/6/14 the well was reclassified as a WAG injector (Sundry 314-427) and was put on MI injection in October 2016. In October 2017, the well went Under Evaluation for IA x OA communication while shut in. Communication was confirmed, and the well was reclassified Not Operable on 11/14/17. The well most recently passed an MIT -IA to 3,000 psi on 10/31/17, as well as a PPPOT-IC to 3,500 psi on 6/7/17. The pressure test data for this most recent MIT -IA will be submitted via email in conjunction with this request. Recent Well Events: 12/29/2017 > Pack -off Leak Path Eval-IC w/gas indicates both seals are good 12/24/2017 > Set TTP @ 8,947' MD, MIT -T Passed to 2458 psi 11/11/2017 > PPPOT-IC Passed to 2000 psi W/ N2 10/31/2017 > MIT -T Passed to 2342 psi, MIT -IA Passed to 3000 psi 6/7/2017 > PPPOT-IC Passed 7/4/2016 > Pulled DSSSV @ 2182', set MCX @ 2159' SLM 3/9/2016 > PPPOT-T Passed 2/21/2016 > Set DSSSV @ 2182' MD, Barrier test passed to 2500 psi 12/8/2015 > Reclassified back to WAG based of Sundry 314-427 approved 08/06/14 10/23/2015 > Pulled TTP @ 8947' MD 10/22/2015 > Set TTP @ 8947' MD MIT -IA Passed to 3500 psi 4/30/2015 > AOGCC MIT -IA Passed to 2400 psi 4/25/2015 > MIT -IA Passed to 2400 psi 11/15/2013 > PPPOT-T Passed to 5000 psi 5/13/2011 > AOGCC MIT -IA Passed to 2400 psi 4/16/2011 > Pull TTP @ 8947' 4/12/2011 > MIT -IA to 2100 psi Passed 4/10/2011 > Set patch @ 8837' - 8853' 3/30/2011 > Set TTP @ 8947', CMIT-TxIA Passed to 2100 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the tubing and casing to 3,000 psi on 10/31/17 demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi, and the outer annulus will be maintained below the normal operating limit of 1000 psi. Proposed Operating and Monitoring Plan 1. Water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2 -year MIT -IA to maximum anticipated injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 4,060 IBM 3.660 3.400 3200 3.060 2.81x0 2.600 2.400 2.260 2.000 1.806 1.606 1.400 1.200 1.660 BOO BOO 400 20D 02+2'. i Well S -11B TIO and Injection Plots 2, 606 2.406 2,200 2. COD 1. SOD 1,600 a 1.40D s 1,2t5G 1.DDO BOD 600 4DO 200 02<<.i; Lu: 4'1 66251' DS 26 i, 1527;17 i 220 20D 180 160 140 m 12013 100 m B0 60 40 20 x,24'1 - OB26/17 10!27117 12128117 TIO Plot f- Tbg —0 IA --- OA OOA --�- OOOA On ■ Bleed Operable + Not Oper ♦ Under Eval Temperature 22.DDO 20.000 15.DOD MOOD 14. DOD a 12.000 10.006 v S. DOD c 6.060 4. DOD 2.000 — WHIP sv — PW — MI GI Other On TREE= 41116'DIW VVELLFFAU- Mr EVOY ACTUATOR= BAKLR 0)0. E.EV = 67.8' BF. E.EV = 39 B FOR.. -._.- 3607 Max Angle = 115 4 10056' Datum MD= 9907 Dakar TVD = 8800' SS 1a 318• CSG. afire• w aitii 2806' 6r1, O=M. l LO/9 Minimum ID = 2.310"@ 8836'- 8859' BKR STRADDLE PKR w/SLD SLV 4-tf2' LNR 14 1r7 TBG. 12.68, L-30, 0152 bpf, D - 3.958' I F'CSG,470,N80,D=8.681• 9136 L-80, .0383 bpf, D = 6 27W _ -{ 9138 r W1s10ac - 9138' PERFORATDN smaiARY REF LOG ON XXfXX1XX ANGLE AT TOP PEE- 80" Q 104W efer b Prod ucbm OB for hstoncal Dail data 2-7f8' 1 4 110495 - 104651 O 108J0M r LMR 26N, L-80, .0371 bpf, D = 6.184' S Y SAFETY NOTES: H2S READINGS AVERAGE 125 ppm WHEN ON Mi. WELL � 70° 0 9557 —[A PAS 10PPG NACL BRINE FROM PKR TO 2605' M D —BEE 72/4/09 AWGRS; CONSULT MRC PRIOR TO ANY MIT IA "' PATCH RAT®OF TO 3500 251 FB'CHECK1iU1L, CHECK TBG CAL PHOT TO PRESSURE TESTING 2162' 47/7 FES X NP, D - 3.813" 4-1f7 LFR 12.611, L-80 MDO, 0152 9927- - Rj5x r BKR NGR INV- 112- BKR STRA F"F PKR -- 111r 1 CMU SLD SL V, D = 2 31' (0411—w11) 41r2' FES X NP D = 3 813' rXNt12'BFQ2S3 F10?D=3.875' 8926• ._ 41/2 HE'S X Fit, D - 3.81 j• 8947' 41rYFESXNNP,ID- 3725 894T 417x2-7f8•14PREDUCWD=2313" 884T 2-78• XX PLUG (12124117) a5/8• x T ElKR UP. D = 8909' NUA4DTTL000NXX I(X j MLLOUTINFIOOW (5118) 9138'-9151' F-y1mbC D1TE RFV BY COA6941S DATE REV BY ooklA M OG18182; INITIAL COMPLETION 97114AB KMJkC TMEGO(07,02JT6) 12/141981 SIDETRACKIS-11A) lDfl7J17 MJMD NINORMSCLEANLIP lr2!Il! LVIJMU SEI XX FLLK;(1212411 r) 0if68199' NOES SDETRACJ(18.110) 02f1U'15 JMCV RILL CHOKE (02)07115) 02722/16 CJFYJMD SETPXFLUG(0212Vt6) 07112116 J J&U FILLED FLUG(07'04i16) F RUD DE BAY LUT W13 -L: 5718 FB;t%ff NO: '1990530 AA ND: 50-029-20725-02 SEC 35, T12M, T12E, 1646' FF18 1855' SP FApbrnfion (Alaska) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.reao0alaska.00vphoeha.brooksOalaska.oov OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD: Prudhoe Bay / PBU I S -Pad DATE: 10/31/17 OPERATOR REP: Adrienne McVey ADGCC REP: Not Witnessed c_hngwallace0alases aov Well S -11B Pressures. Protest Initial 15 Min. 30 Min. 45 Min. 60 Min. 0= 0Per(dexriEe in Notes) 4=Foot Year Cycle PTD 1990530 type Inj N Tubing 27 238 247 245 0= an., tde¢cnCe In Matt Type Test P Packer ND 8392 BBL Pump 132 IA 723 3284 3229 3212 1 1 Interval 0 Test psi 2098 BBL Return 1 6.8 1 OA 790 828 1 827 1 827 1 Result P Notes: Propose to use this III to sat anniversary date t ACminisealive Approval for continued water injection is granted. Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Protest Initial 15 Min. 30 Min. 45 Min. 60 Mtn. PTD Typelnj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Ing Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTDType Inj TubiN Type Test Packer rVD BBL Pump IA Interval Test psi BBL Return OA Result Noes: Wall Pressures: Protest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi I BBL Retum OA Result Notes: Well Pressures. Pretest Initial 15 Min, 30 Min, 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Retum OA Result Noes: Well Pressures. Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test-] Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Cod. TYPE TEST Co4ea INTERVAL Chea Result Code W=Water P=Ressre Te -1. 1=Most Test P=Paw G=Got 0= 0Per(dexriEe in Notes) 4=Foot Year Cycle F=Fall S=Sony V= Repmred by Venice 1=lnwnclooNe I=mdusaal wast ter 0= an., tde¢cnCe In Matt N =Not ecar, Form 10426 (Revised 01/2017) MN Pau Est I 10x1-170sr 16 BP Exploration (Alaska) Inc. Aras Worthington, Well Integrity Engineer Post Office Box 196612 Anchorage, Alaska 99519-6612 February 9, 2017 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well R-02 (PTD # 178-100) Request for Administrative Approval for Water -Only Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for continued water injection into Prudhoe Bay well R-02. The wellbore is currently classified as a water alternating gas (WAG) injector. A packer squeeze was recently completed in November 2016 (Sundry # 316-410) to alleviate TxIA communication via a 5-1/2" sliding sleeve. The well was put back online injecting water and passed a state witnessed MIT -IA to 2227 psi on December 20, 2016 which indicates two competent barriers. R-02 began to exhibit signs of IA re -pressurization in early January 2017 and was placed under evaluation on January 21, 2017. The IA can be managed by bleeds to remain under NOL and currently has a build-up rate of —67 psi per day. In summary, BPXA has determined that Prudhoe Bay well R-02 is safe to operate as stated above and requests Administrative Approval for continued water injection operations. If you have any questions, please call me at 564-4102 or Jack Lau/ Adrienne McVey at 659- 5102. Sincerely, Aras Worthington BPXA Well Integrity Engineer Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Jack Lau / Adrienne McVey GC2 Operations Team Leader Ryan Rupert Ryan Daniel Prudhoe Bay Well R-02 Technical Justification for Administrative Approval Request February 9, 2017 Well History and Status R-02 was originally drilled in 1979 and then was worked over in 1983. Zone 4 perforations were added in 1987. In 1988 Sag perfs were added and injection was in both the Sag and Ivishak. In April of 2004, the Ivishak perfs were squeezed off and injection has been Sag only since that time. In August 2011, the well was shut-in due to IA pressure exceeding NOL. A subsequent MIT -IA failed with a LLR of 2.6 gpm @ 2500 psi. To investigate this, a caliper log was run in August 2011, and both tubing and liner were in good to fair condition. In September 2011, a LDL showed a leak around the sliding sleeve at 8659' MD. SL shifted the sleeve closed in December 2011 but the following MIT -IA failed. The sliding sleeve was confirmed as the source of the leak and sleeve parts were ordered for a repair Isolation sleeves were set across the sliding sleeve in both 2012 and 2013, but neither proved to solve the issue. A packer cement squeeze was pursued in 2016 (Sundry # 316-410) and placed TOC at 8358' MD, isolating the sliding sleeve. The well was put back on injection and passed a state witnessed MIT -IA to 2227 psi in December 2016. In early January 2017 the well started showing signs of IA re -pressurization at a rate of —67 psi per day. Currently the IA is manageable by bleeds at a 12 to 14 day frequency. Recent Well Events: > 09/12/09: AOGCC MIT -IA Passed to 2500 psi > 08/17/11: Caliper from 9389' to surface - 118 jts < 20%, 57 jts 20-40% > 08/21-23/11: MIT -IA Failed LLR-IA 2.6 gpm @ 2500 psi > 09/12/11: LDL found sliding sleeve leaking > 12/17/11: MIT -IA Failed, Leak too small to establish a LLR > 09/23/12: MIT -IA Inconclusive, CMIT-TxIA Passed to 2500 psi > 10/19/12: Set isolation sleeve across sliding sleeve > 10/19/12: MIT -IA Failed, MIT-T Failed (tubing and IA tracking) > 11/04/12: MIT-T Passed to 2450 psi, MIT -IA Failed, LLR 7.3 gmp @ 2450 psi > 09/06/13: MIT-T Passed to 2500 psi, pulled TTP from 8833' MD > 09/21/13: MIT -IA Failed > 10/18/13: Set XX Plug @ 8833' MD > 10/19/13: MIT-T Failed, MIT -IA Failed, CMIT-TxIA Passed to 3000 psi > 12/25/13: Set isolations sleeve across sliding sleeve, Could not pressure up down IA, tubing tracked > 02/19/15: PPPOT-T Passed to 5000 psi, PPPOT-IC Failed > 06/20/15: Pulled isolation sleeve > 06/22/15: CMIT-TxIA Passed to 2500 psi, > 11/12/15: PPPOT-IC Failed > 12/03/15: Pulled TTP from 8833' MD > 12/04/15: Caliper 7" tbg 52 jts 0-20% & 25 jts 20-32%, 5-1/2" & 4-1/2" tbg 112 jts 0-20% & 66 jts 20-34%. Set Evo-Trieve @ 8609' SLM, Barrier Test Passed to 3000 psi > 12/05/15: MIT-1A Failed, LLR=0.35 bpm @ 2500 psi, MIT-OA Passed to 1200 psi, Pull Evo Trieve > 11 /11 /16: Packer cement squeeze > 11/17/16: Set TTP at 8833' MD > 11/18/16: CMIT-TxIA Passed to 3461 psi, MIT-T Passed to 3472 psi, Pulled TTP from 8833' MD > 12/20/16: AOGCC MIT -IA passed to 2227 psi > 01/23/17: PPPOT-T Passed Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 2,227 psi, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line, and the outer annulus will be maintained below the normal operating limit of 1000 psi when the well is online Proposed Operating and Monitoring Plan 1. Water injection only 2. Record wellhead pressures and injection rate daily 3. Submit a monthly report of well pressures and injection rates to the AOGCC 4. Perform a 2-year MIT -IA to maximum anticipated injection pressure 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition Well R-02 TIO Plot Well R-02 Injection Plot TFEE 6-3/8' CNV — V431H AD= MCEVOY _ R —O 2 WHENI ON MIS"' WELL REQUIRES A S: K2S READINGS SSSSVE 1WHEN ON MI ' ACTUATOR = BAKER C INITIAL KB. E E 54.9T BF. ELEV = 19.38' KOP = 33W Max Angle = 32' Q 8226 —" CONDUCTOR, ? Datum MD = 9612' _#, _. 2980' 7" X 5 ilY XO, F = 4.892' Datum ND = 8800 SS D = _" 13-3/8- CSG, 72#, L-80, D = 12.347- 2628' S-1t2- CAMCO SSSV LANDING NP, D = 4.562- 7' TBG, 26#, L-80, .0383 bpf, D = 6.276' 2980' GAS LFT MANDRELS Minimum ID = 3.725" @ 8833'� 4-112" OTIS XN NIPPLE 1 5-1 /2- TBG, 17#, L-80, .0232 bpf, D = 4.892" 1--1 8741' 1 TOPOF 7" LNA2 I-i 8815' 4-1/2- TBG, 12.6#, L-80, .0152 bpf, D= 3.958" 1--� 8876' 19-5/8- CSG, 47#, L-80, D = 8.681- 1—I 930T I PERFORATION SUlAMARY REF LOG: SVVS- BHCS ON 07/02/79 ANGLE AT TOP 29' @ 9364' Note: Refer to Production DB for hstoricai perf data SIZE I SPF I INTERVAL I Opn/Sgz I SHOT I SOZ SEE PAGE 2 FOR PE IWORATIDN DETAILS u-j 10225 7- LNR, 29#, L-80, .0371 bpf, D = 6.184- 10302' ST MD ND DEV TYPE VLV LATCH PORT DATE 8 3147 3145 8 OTIS DW RA 0 07/13/84 7 5096 4933 28 OTIS OW RA 0 07/13184 6 6572 6233 29 OTIS DNM RA 0 07r13/84 5 7637 7159 31 OTIS DW RA 0 07/13184 4 8225 7662 32 OTIS DW RA 0 04/18/83 3 8362 7777 32 OTIS 'DW RA 0 04/18/83 2 8460 7860 32 OTIS 'OW RA 0 07/13/84 1 8593 7973 32 OTLS 'DA11' RA I 0 07/13/84 U T VLVJI.aV I J111]1110 8368' - 8677' CTM CMT IA (1 v1 t/16) 8659' S-Il2' BKR L SLD SLV, D = 4.313" 867T - 8678' CTM TBG RI CH (i t/10/1 s) 8717' TBG SEAL ASSY 8741' 9 5/8- X 5-1/2- BOT 3H PKR D = 4.75- 8741' 5-1/2- X 4-1/2- XO, D = 3.958- 8792' 4-1/2" OTIS X NP, D = 3.813 $� 4-1/2- OTIS XN NP, D= 3.725' 8876'-14-1/2" TBG TAIL, D = 3.958- 8878' t3MD TT LOGG®12/15/89 9379' CTM FISFt MLL®BKRCBP(tlttt/16) 9405' ESTMATEDTOC (TAGG®05/28t04) 9580' SAND PLUG (05/28/04 EBT TOP OF C(3✓BVi (07114194) 1 9663' 1-gMARKERJONTI 1 9925' I —I FISH - 3' BKR BP j PRUDHOE BAY UNIT WELL: E,02 PERWT W: F1781000 ARW: 50-029-20354-00 SEC 32, T12N, R13F 637' FSL 8 969 FVVL (DATE REV BY COMM34TS DOTE REV BY COM ENTS 07/08179 ORIGINAL COMPLETION 07/24/15 PJC BF B_EV UPDATE (BELL 2012) 04/18183 RNO 07/29/15 PJC PE W CO RECTIONS 11/26/01 RWTP CORF�TIONS 12J07/15DLWJM)TILEDFISH& PLUG (12fCW15) 11/05/13 JMM'J PULL SLV/SET RUG (10/18-19113) 06/07/16 RCR/J PULLED NP RtDt1(,H2 (12/03/15) 08/01/14 JMNJ SET ISO SLV/SLP STOP (12/25t13) 11/29/16 AOnLH TBG RICK CMT IA, MLL CBF(11112/16) IBP Exploration (Alaska) 07/09/15 PVVC/AC, PULL ISO/SLPSTOP 8 2 FISH R-02 PERFORATIONS PBW< ATION SUK MRY W LOG: SMS-BRCS ON 07/02/79 ANGLEAT TOP FEW 29- Q 9364' Note: Refer io Roduckon OB for habixal perf data SPF NTEFWAL OpmSW SNOT SC17 ? 9364 - 9404 S 05/2 Vffi 09/1289 4 9364 - 9404 0 10/ M9 r3ffi" ? 9510 - 952o S 06/21/84 1a10I85 9510 - 952D S 10/17/85 09/12/89 4 9510-9520 S 10/10/89 05M04 ? 9530 - 9576 S 06/21/84 10/10/85 2-7/8' ? 9530 - 9576 S 10117/85 MUM 33/S' 4 9530 - 9576 S 10°f0/89 05/28R)4 3-&W 4 9576 - 95W S 10/10/89 05/28104 3-3/8 4 9590 - 9614 C 10/10/89 05✓L8/04 2-7/8" ? 9590 - 9636 S 06/21/84 10V10B5 2-7Ar ? 9590 - 9636 S 10/17/85 09/12/89 3-3V 4 9615 - 9636 S 12/15/89 07/14/94 2-7/9' ? 9662 - 9687 S 01/17/80 10/10/85 3-38' ? 9670 - 9687 S 11/19/87 09/12/89 3-3W 4 9676 - 9687 S 12/15/89 07/14194 2-7Ar ? 9697 - 9730 S 01/17/80 10/lW5 3-&W 4 9700- 9710 S 12/15/89 07/14/94 3-3ff 4 9745 - 9788 S 10/10/89 07/14/94 3-3W ? 9745 - 9789 S 11/19/87 O9/12l89 FRUDHOE BAY Lldr VVE-L R-02 PEFOfTND' '1781000 API No: 50-029-20354-00 SEC 32, T12K F:73E, 637' FSL & 968' FWL DOTE fall/ BY COMINTS DATE REV BY COMP NTS 0710809 ORMINAL COMPLOWN 07/24/15 PJC BF ELEV LPDATE(BELL 2012) 0411W83 RWO 07/29/15 PJC PEW C IS 11/26/01 RWTP CORFEDIIOFS 12107/15 DU -VAC Pl1LLMFISH & PLUG (121(4/15) 11/0&13 AWAV PULL SLV/SET PLUG (10/18-19/13) 06107/16 RClbJM) PU.LEO NPRMUCER (12/03(15) 08101/14 AMAD SET ISO SLV/SLPSTOP (12I25/13) 11/29/16 AOM-H TBGR")KCMTW,MLLCSP(11/12/16) BP Exploration (Alaska) 07/09/15 P%ACJK,PULL ISO/SLPSTOP& 2 FISH 15 by ALAA BP Exploration (Alaska) Inc. Aras Worthington, Well Integrity Engineer Post Office Box 196612 Anchorage, Alaska 99519-6612 February 2, 2017 Ms. Cathy P. Foerster AMECEIVED Alaska Oil and Gas Conservation Commission 333 West 7th Avenue FEB 6 8 2017 Anchorage, Alaska 99501 Subject: Prudhoe Bay Well Z-19A (PTD # 2061050) AOGCC Request for an Administrative Approval for WAG Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests an Administrative Approval (AA) for water alternating gas (WAG) injection into Prudhoe Bay well Z-19A with an increase in outer annulus (OA) normal operating limit (NOL — formerly MOASP) to 1500 psi. Well Z-19A was operated as a WAG injector under AA NO 3.017 from 5/17/07 to 12/22/11 for OA repressurization. That AA was cancelled when it was determined that the OA repressurization was not manageable by bleeds with a 1000 psi OA NOL and the well was made not operable at that time. The OA pressure now stabilizes between 900-1100 psi. BPXA requests an AA to raise the OA NOL from 1000 psi to 1500 psi. An engineering analysis and well barrier risk assessment have been completed and it has been determined that raising OA NOL to 1500 psi is within the safe operating limits of the installed equipment. In summary, BPXA has determined that Prudhoe Bay well Z-19A is safe to operate with the increase in OA (7" x 10-3/4") NOL to 1500 psi. BPXA requests an AA for WAG injection operations. If you have any questions, please call me at 748-1140 or Jack Lau/ Adrienne McVey at 659- 5102. Sincerely, �� Aras Worthington BPXA Well Integrity Engineering Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey GC2 Operations Team Leader Eric Zoesch Ryan Daniel Aras Worthington Prudhoe Bay Well Z-19A Technical Justification for Administrative Approval Request February 2, 2017 Well History and Status Z-19A was originally drilled and completed as a gas -lifted producer in 1992. There is no history of OA pressures during the time it was producing. The well was shut-in in 1996 due to high water cut and poor tubing. It remained shut-in until a RWO and Rig Sidetrack were completed in September 2006, converting Z-19A to a WAG Injector. The plan for the Sidetrack was to exit below the 10-3/4" SC shoe, but while attempting to mill the 7-5/8" PC, a sidetrack window was inadvertently cut in the 10-3/4" SC. This window was dressed off to 2,427' — 2,445', exited, and the well was completed to TD. Hydrates were encountered multiple times during drilling, with two notable zones: 2,650' — 2,840' and 2,909' — 3286'. New 7" PC was run to depth and cemented in 3 stages: bottom stage through the float, second stage through an HES ES Cementer at 8,557', and an OA (7" x 10-3/4", 0.0486 bpf) downsqueeze from surface. The OA downsqueeze consisted of 132.6 bbl of 11.6 ppg LiteCrete with Gasblok. After waiting on cement a pressure test of the OA passed to 1,000 psi, charted by the rig. TOC was strapped at 82 ft on 8/07/2016, from both annulus valves, twice on each side for confirmation. Once Z-19A was put on water injection the OA began to exhibit signs of pressurization, 900- 1,100 psi. An AA (AIO 3.017) was granted by the state for continued operation, conditioned upon maintaining OA pressure below 1,000 psi. Approval of the AA by AOGCC required an OA gas sample, which indicated the source as shallow hydrates. The well was unable to be maintained below 1,000 psi per BP's manageable by bleeds criteria, and AOGCC amended the AA, raising the maximum OA pressure to 1,500 psi. A deviation to internal BP Policy was not sought at that time, and the well was shut-in, made Not Operable, and AOGCC cancelled the amended AA. Based on the verification of mechanical integrity of two barriers via passing MIT -IA and a passing pressure test of the OA, a deviation is warranted to raise the OA NOL to 1,500 psi. Raising NOL will also reduce the risk associated with multiple and repetitive OA pressure bleeds currently required to maintain OA pressure below current NOL of 1,000 psi. This revised NOL of 1,500 psi is sufficiently below the 45% burst rating (2,479 psi) to allow timely response by Operations or DHD to bleed OA pressure and avoid reaching the 45% threshold. Recent Well Events: > 12/11/06: AOGCC MIT -IA Passed to 4000 psi > 12/16/06: DSO call in high OAP > 12/17/06: OA has rapid OA repressurization > 12/17/06: AOGCC notified of high OAP > 12/17/06: OA Fluid Packed w/ diesel, high OA is due to hydrates in Outer Annulus. > 12/19/06: MITOA Failed > 04/04/07: Jim Regg requested an OA gas sample before he will sign the AA, gave permission to flow well if hydrates need to be thawed for sample. > 05/17/07: AA 3.017 approved for WAG > 07/14/07: DHD identified leaking LDS on OA casing hanger > 07/15/07: Tightened glandnuts on casing head > 07/17/07: MITOA Failed, LLR to small > 08/06/07: OA Fluid sample taken, found to be diesel > 11/10/07: OA bleeds turned back over to operations > 03/20/08: MITIA Passed to 2000 psi. Left 1900 psi on the IA to test OA repressure rate > 04/14/08: Reviewed IAP plan with APE, will send a revised plan to WIE > 06/07/08: TecWel LDL found anomalies @ 2600' & 4960' > 06/08/08: Reclassified as Operable, OA repressurization appears to be manageable. Decided not to pursue internal dispensation at this time. > 07/26/09: Conductor treated w/ 1.7 gal RG2401 > 10/09/09: MIT-OA Passed to 2000 psi > 12/22/11: AA for high OAP from hydrates cancelled - well cannot be maintained below MOASP > 10/01/16: MIT-OA Failed, Confirmed Upper SH leak to liquid (passes OA pressure test criteria) Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A passing pressure test of the inner annulus to 4,000 psi, which tests both barriers, demonstrates competent primary and secondary barrier systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. WAG injection. 2. Record wellhead pressures and injection rate daily. 3. Submit a report monthly of well pressures and injection rates to the AOGCC. 4. Perform a 2-year MIT -IA to 1.2 x maximum anticipated injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the wells mechanical condition. 6. BPXA shall limit the well's outer annulus pressure to 1500 psi. Well Z-19A TIO Plot *OM 3.00D {1I + .t MP —0 Tbq —.-- M OA OOA -.00OA on Well Z-19A Injection Plot 1.1-10D I'M 1,7M 1,6M 1,5w IAM 1,3DD 12CO 1.10D X� I'ODD 90D MD 70D GDO w 400 300 2DD 100 0112505 Q2515 01'2&15 0412&115 OSrA,15 OVA115 F/M15 08%15 093015 IMI, )U3�16 GMA'16 , - OM'16 IM16 11,%16 l2ib7;16 Vm1p sw Kq w -GI 00M or, TF4T = 4- 1116' CNV WELUIFAD= FKC fACTLATOR= BAKER 87' BF EIEV 54,17 MF M* Max. Angle = 65'@597EV I PatumKO= 12W MAUM TVD 88i3p'SS 14-112" H ES X NIF 17-5/8- CSG sT"o (0&lwoo H 2458__ csa, -4 "4. -L-vi �3023' j?!VS'SSG CAJT(MTF1') 3225- 1/2"T13GSTLE(07127109) H 4000' 7-SW CSG, 29,7#. L-80 NSCT X0 TO C-80 EITC 7-W"CSG, 29-7#, CM STC, ID - 6,875' PEM�O%4TUNS~RY REF LOG: 94VS LVVD M FWS ON MOM AW-CE AT TOP PEFF, 17° @ 12804- Nole. Wfet to Produ0m DO fat histur" pert data 4E: L 2 , 2. J]E 6 4 4r9�ASA 1 n 1111171ni 1;2"TBG, 125#, 80 TCl, -0152 bpI, =3 nr 1 7' CSG, 26# t-80 STC-k( 10=6.27tr 4-IQ'LW IZ5#, 131 L-80 OTC-M, 152 bpf, ID = 3.958' 4022' —12!�TED �TOC 444r �—j 7' CSG, 260 L-80 TC1 O TO L-80 EITC-m 12385'14-112- hiT6 = 3 813- r X A - 112" BKR S-3 WJ� D = 3 815- -1 I247I' j-{4-112'HMXMPl)=3813' 11 12492' 12560- j-j7-X5-8KRLTP,"0=4.4ocr 12604' -12-51r —fr X Y 8XR FLEX LOCK I HGR E) = 1875- 1 -W�-5x j 4 26 -fF---ur xo, u = 3.959- 1 13026' J--jPffM(TA lollaw.,[ I -7 FfaJCF*)E BAY Lw WELL Z-19A pe;w w '2061050 ARW: 50-029-22251-01 SEC 19, TI I R 812F- 994' FN- & 2031 FWL a-TE-TREV BY 008118iFS 0923192 UNOM VROWL. COMPLETM =IV% i WES ISIDEMCKA" IIJI7106 7TFUPAG41PGT-ORAT)ONS 12)19M7, 00 PRC DFLG DRAFT COFOL-DONS 02M6111 MEVADTADDED SSSV SAFEFY NOTE SP Fkpimation (Alaska) 14 BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineer Team Leader Post Office Box 196612 Anchorage, Alaska 99519-6612 September 07, 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 r*J SEP 15 2016 AOGCC Subject: Prudhoe Bay Well P-06B (PTD # 2051380) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue water injection operations into Prudhoe Bay well P-06B (PTD # 2051380). Well P-06B exhibits inner annulus (IA) repressurization of approximately —180 psi/day while on gas injection. However, a pressure test of the inner annulus passed to 2500 psi on 05/27/2016, indicating two competent barriers to formation. If continued operation of the well is granted, the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi and limited to water injection operations only. In summary, BPXA believes Prudhoe Bay well P-06B is safe to operate as stated above and requests administrative approval for continued water injection operations. Any continued signs of slow IA repressurization will be managed with periodic annular bleeds. If you have any questions, please call me at 748-1140 or Jack Lau/ Adrienne McVey at 659-5102. Sincerely, Ryan D BPXA Well Integrity Engineering Team Leader Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey GC1 Operations Team Leader Travis Alatalo Ryan Daniel Prudhoe Bay Well P-06B Technical Justification for Administrative Approval Request September 07, 2016 Well History and Status Prudhoe Bay injection well P-06B (PTD # 2051380) shows signs of IA repressurization while on gas injection. An MIT -IA to 2500 psi performed on May 27, 2016 passed, demonstrating competent tubing and production casing. This well had as Administrative Approval (AA) for continued water injection approved in 2007 due to tubing by IA (TxIA) communication while on MI. However, AA 3.015 was cancelled in 2009 after dummy gas lift valves (GLVs) were changed out and communication ceased. The well began to show signs of communication again early this year after being placed back on MI. GLVs were again changed out but communication has not been mitigated. Inner and outer annulus operating pressure can be maintained below MOASP. Recent Well Events: > 03/13/07: AA 3.015 approved for continued water injections > 11/04/09: AA 3.015 canceled after GLV change out mitigated communication > 04/18/16: PPPOT-T Passed > 05/01/16: MIT -IA Passed to 2500 psi > 05/27/16: GLV change out, MIT -IA passed to 2500 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 2500 psi, demonstrating competent primary and secondary barrier systems. Pressure on the inner annulus is maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 4-year MIT -IA to maximum injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well P-06B TIO Plot WOO P Ob 4.OM ?,OW 2.000 i.000 —41�- Tbg -♦•-- A OA OOA OOQA On Well P-06B Injection Plot Well P-O6 34 3.3 3.2 :.t 3.G 25 2.S 2s 2.F. 2,4 z._ j 2: zt 2( a Lf t.E I t! t: t( 1 t2,0M nnoo tom 9.Ow B.000 c TOW 5AM 1,6((? 3,Ow ZOO am - Vm1p 7- Sy p - MI - GI 6Ma BEM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: iim.regcl2Dalaska.aov: AOGCC.InspectorsCrDalaska.aov: phoebe. brooks@alaska.pov chds.wallace(cDalaska.gov OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD: Prudhoe Bay / PBU / P DATE: 05/27/16 OPERATOR REP: Whitney Pettus AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well P-06B Type Inj. I G TVD 8,683' Tubing 124 142 144 145 1 1 Interval 0 P.T.D. 2051380 I Type test I N d Test psi 2170.75 Casing 337 2,476 2,456 2,456 P/F P Notes: MIT -IA to evaluate for Administrative Approval OA 38 43 42 42 Used 15 bbls diesel to reach test pressure, bled back 5 bbls Well I I Type Inj. I I TVD I Tubing Interval P.T.D. I Type test I I Test psi I Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: OA Well Type Inj. I TVD I Tubing Interval P.T.D. I Type test Test psi I Casing P/F Notes: OA Well I Type Inj. I TVD I Tubing Interval P.T.D. I Type test I I Test psi I Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes D = Drilling Waste M = Annulus Monitoring G = Gas P = Standard Pressure Test I = Industrial Wastewater R = Internal Radioactive Tracer Survey N = Not Injecting A = Temperature Anomaly Survey W = Water D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance 0 = Other (describe in notes) Form 10-426 (Revised 11/2012) MIT PBU P-06B (PTD# 2051380) 05-27-16.xls TFEE = 4-1116, aw V4E14B D= SM RC AMI)ATOR = Offs KB. R = 77.9(Y BF. ELEV = 55.41' KOP = 49W Max Angia = 103'§ 1057T Datum W = 11964. Datum TVD = 8800' ;Sj Minimum ID =2.37"@ 10909' TOP "O'F-2-'7/8"'LN'R'' 3-1/L-LW8-81#,L-80M-M7bpf, lD= I Top OF 5.1r2- LM 4-1/2- TBG, 12 M, 113-CP, 0 152 bpf, 1D = 3, 9W VWN'ISTOCK (10113/05) 1-4 —"i4r —F.Lm F91FORAMNSUMMkRY REF LOG: 100UMSOMSROPON 100905 ANGREATTOPPS;F- 8T@ 1092T Note Refer to Poduction OR for tistoricai part data SIZE sw INTERVAL opntsqz DATE 2" 6 10925-11050 0 IOW)05 2" 6 11490-11530 6 C 10/27M SAFETY NOTM, H28 REACINGS AVERAGE 125 PIS P -06B WHENONMI, W1041RE-GUAWSA SSISVIVNIEN ON ME ORIGINAL "I WELL P. 1 06) . IS NOT 11 S I H OWNOM MAGR AM. '"'4.1/2" CHRIDiI E THGO-WELL ANGLE TT G 10183'. 0 I i 2103' nAlliFTIMAPOIRRS ST, MD TVU CEV TY FE VLV 1LATCHIFOW DATE "5 5 5 2185 29115 0 CA"10 *DW Bll 0 05727116 4 5614 5481 24 CAMOD TW SK 0 MaM 3 r 7779 -1124 3,9 CAMOD *OW 611 0 050-1116 2 92617 8389 43 CAhM 'DMY BK 0 05127 1 9636 8664 44 rAk4M -nLf - a I A IM, WN 4'% 0 NO , LM T 0 rlMV r. rTQU9MJMClMr%P rPk%,VMrW, '"MANURE COVeREDwiCOMENTJIMMDIMS) ±M- PKR SVVS NP. 0- 1813- (0041ND PIPE) 9977" 7-5?8" X 4-112- TTN HBBP PKR (BM PIPq 973j"--j4-11-PKR WANRMILLFDT03W I SEHM CT UNR 9 4. lr2- WLEG, ID = 3.95fr NOTE-, TAILPIPE WAS BACKED OFF A IS FASTING ON 5-W LNR TOP L4LLOUT VWCM(P-06B) 9974'-9907 I 109W H3-3116-X2-fl8'X0,lD=2.441' I 3-\ rl 3116- LNR &W 2N, L-TCII, --- ; 109W 1145W 2 -1 -Iff (3F8 0076 bpf, ID = 2.80" 1wel In �1110) 13-70'BKRFETRIEVALSE BPw/SU4'OWPIPE TOTD 1--f 116W 12-7,RrLWa-ia*,L-sosTL,.0058bpf, W-F PRLJDHDE BAY UNIT V4ELL, P-066 PBRIAT M: IM51380 AR No: 50-029-22166-02 SEr, 31, Tl IN, R13F- 2506'FSL & MY FW1- DATE REV BY ! COWM34T5 DATE REV BY I Colifill" I D&MI _ SJA 'ONGINALCOMPLETION 04/27J12 'RCT/ PJC SET PA PLM (4118112) 1=M7 � CTD SIDETRACK (P-0151A) O6/Ml2 RKT/JPwU RILED PXR-UG (OU01112) 10129105 -PARKER NORDICI �CM RACK("68) 0513116 JAPJ&AD O9/22110 SMPJr,! SET C3BP (M1110) 02110fI I MJM jAMM&S.WSAFETY NOTE. RP Ehplaration lAhaka) I 9111 2 _��j 13 by BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineer Team Leader Post Office Box 196612 Anchorage, Alaska 99519-6612 July 28, 2016 Ms. Cathy P. Foerster RECEIVED Alaska Oil and Gas Conservation Commission JUL 2 9 2016 333 West 7th Avenue Anchorage, Alaska 99501 AOGCC Subject: Prudhoe Bay Well X-24A (PTD # 1991250) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue water injection operations into Prudhoe Bay well X-24A (PTD # 1991250). Well X-24A exhibits manageable inner annulus (IA) repressurization of approximately -90 psi/day while on water injection. However, a pressure test of the inner annulus passed to 2500 psi on 06/07/2016, indicating two competent barriers to formation. If continued operation of the well is granted, the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well X-24A is safe to operate as stated above and requests administrative approval for continued water injection operations. The slow IA repressurization will be managed with periodic annular bleeds. If you have any questions, please call me at 748-1140 or Jack Lau/ Adrienne McVey at 659-5102. Sincerely, i Ryan Daniel BPXA Well Integrity Engineering Team Leader Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey GC3 Operations Team Leader Wade Bowman Ryan Daniel Prudhoe Bay Well X-24A Technical Justification for Administrative Approval Request July 28, 2016 Well History and Status Prudhoe Bay injection well X-24 (PTD # 1991250) shows slow signs of IA repressurization while on water injection. A recent MIT -IA passed, demonstrating competent tubing and production casing. Inner and outer annulus operating pressure is maintained below MOASP. Recent Well Events: > 10/16/15: MIT -IA Passed to 2500 psi > 12/22/15: AOGCC MIT -IA Passed to 2500 psi > 06/07/16: MIT -IA Passed to 2500 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 2500 psi, demonstrating competent primary and secondary barrier systems. Pressure on the inner annulus is maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 2-year MIT -IA to maximum injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. am S mmi in Well X-24A TIO Plot Gt(i15 1215f15 1219 t5 O; t? 16 012616 02%16 0221,16 03t0&16 03°2 A 041516 WTI 05%116 CGITI6 06-3116 %1416 06,2&16 07I T16 O'i2616 —0-59 -f— IA OA OOA a - OOOA On Date SW/End 7l26C2015 7t2&R016 Rebad Plat TOW Save to Opboard Cursor VA X 07/% 015 Y 4.406 Well X-24A Injection Plot 1,9W 1,300 , 00 1,Gm 15D0 1,400 1,300 1,200 MOO =1,ODD 3 900 800 700 600 5W 4W 300 200 100 w 15,000 14,00 u 12,OW 11000 10,000 9,000 0 8,OW T e 70W 6,oW 5000 4.OW 3,000 2,O00 ON Date %vtl&rd 7/2V2015 712VA16 R" Not hGid Log Scale Ta Qgb — Gaaer v" X 07/172015 Y 2,107 — WHIP sw — pal — MI — GI —Ofm On Tlrffi = 4* CW WELU FAD = NCEVOY ACTU&TOR - AMtk KB. ELEV = 752T BF ELEV - 39-n KCP = 4700' �Lbx Angle = gr @ 9570' butimn mD 9931 Daum TVD = 81W ss 6�1-i2i' L-W, 9)--' IMinimum ID =2.372"@ 8894' 2-718" LINER TOP OF 7' LNR H BOW 4 1" T12C, I 2AV, L 20, ID - 2.062- FFf7FOMTIDNS~RY W LOG'PVS Nn'GR ON 0111WOO ANCLEAT-TOPFEW. 7W 0 98W Note, Ref*r to Production DB for hidarical pert data SIZE SPF INTERVAL OpWW FATE Z 6 9800-9820 0 lir"i ZI 4 1 L&= - Urdw t; Lnllwuu SAFETY NOTES: HZS HEADINGS AVERAGE 125 ppm VA ON Mi. WaL REOWIES A SSSV WHEN ON X-24A 91. WWLL ANGLES -70- @ $321', 2146• j_j4-lM-OTlSDBE SSSVNPD=3.813- I W HO-5ar.4-1/2-80Fr-3KRCRID=3.968-I I SWV -�44-112'OTlS')CHPK)=3.8I3" I i SNjr H4-VTOTIBMLLEI)XNNPID=3.906- IWLOLffvwcuw91w-m =_1 10097' H2-l/8r8KRIBP(llM -T 10=fr -TTOPOFFLL 2-71W L NR 6 160, L-80, 0055 W, ID = 2 372- H 1035r DATE REV BY C06SUNI7S DATE FIEV BY CORSAENTS "'21M4 01190) CJS om"L comet-Enom CTDSKXTRKCOMPLErM 1112= UOSM JDWWTLP RWSV CLOW, PEW TREECJO(MMM) 02r24M SB-QOtA OOMIBTM TO CANVAS 0216/11 MYJAD ADCEDSSSV SAFETY NOTE 03M2101 W-W R14kL oirmV TMWW ADCED 112S SAFETY NDTE 061I8/01 WTP , CORFECTK)NS CVW PJC PEW aMECMN 11/28t01 jAID%AKjFEWS; IBP. FLL 107119114 i I fill DHOE BAY LHF VVS-L X-24A FOUL W '1991250 AM W 50-029-2109"1 SM 6. T10K R14F- 244'NSL 3 407 VOR SP Exploration (Alm ka) 12 BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineer Team Leader Post Office Box 196612 Anchorage, Alaska 99519-6612 July 27, 2016 RECEIVED Ms. Cathy P. Foerster JUL 2$ 2016 Alaska Oil and Gas Conservation Commission 333 West 7th Avenue AOGCC Anchorage, Alaska 99501 Subject: Prudhoe Bay Well S-41A (PTD # 2101010) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue water injection operations into Prudhoe Bay well S-41A. Well S-41A (PTD # 2101010) was completed in 2010 as a producer then converted to an injector in 2013. First injection was in May of 2014, when the well was placed on gas injection. The well began showing signs of inner annulus (IA) repressurization of —90 psi/day while on gas service, with the IA repressurization rate increasing to 150 psi/day following a passing MIT -IA to 3000 psi. A leak detect log (LDL) found a leak at gas lift station two. The well was placed back on gas service to monitor the IA repressurization rate after changing out gas lift valve two but the repressurization had not been mitigated. However, a pressure test of the inner annulus post valve change out passed to 4000 psi on 11/18/2015, indicating two competent barriers to formation. If continued operation of the well is granted, the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well S-41A is safe to operate as stated above and requests administrative approval for continued water injection operations. There is no history to indicate IA repressurization on water service. If you have any questions, please call me at 748-1140 or Jack Lau/ Adrienne McVey at 659-5102. Sincerely, Ryan Daniel BPXA Well Integrity Engineering Team Leader Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Lau/McVey GC2 Operations Team Leader Matthew Bergene Ryan Daniel Prudhoe Bay Well S-41A Technical Justification for Administrative Approval Request July 15, 2016 Well History and Status Prudhoe Bay injection well S-41 (PTD # 2101010) showed signs of IA repressurization while on gas injection. A leak detect log found a leaking gas lift station. The valve was replaced and the well pressured tested, before placing the well back on gas service. The IA continued to show signs of repressurization but a recent MIT -IA passed, demonstrating competent tubing and production casing. Inner and outer annulus operating pressure is maintained below MOASP. Recent Well Events: > 03/03/14: Dummy gas lift valves (injector conversion) > 03/04/14: MIT -IA Passed to 4000 psi > 05/18/14: AOGCC MIT -IA PASSED to 2500 psi > 01/15/15. PPPOT-T Passed to 5000 psi > 02/04/15: MIT -IA Passed to 3000 psi > 11/15/15: Leak detect log finds leak at sta #2 > 11/17/15: Set dummy gas lift valve w/ extended packing in sta #2 > 11/18/15- MIT -IA Passed to 4000 psi > 03/19/16: PPPOT-T Passed Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus passed to 4000 psi, demonstrating competent primary and secondary barrier systems. Pressure on the inner annulus is maintained below the normal operating limit of 2000 psi when the well is on-line. Proposed Operating and Monitoring Plan 1. Allow water injection only. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform a 4-year MIT -IA to maximum injection pressure. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well S-41A TIO Plot S-41 T 10 RW 4,000 RM um KCM 07Ji4 i4 09,14,14 09 wI4 7C,1514 11,15,14 12!!&'14 (111&115 0Df.115 01,1*15 04,19,15 W2a, 15 06,2615 2 1, 1 5 0"Vl� ft1t 15 1 V21115 I.M15 01 A16 UZI 6 �J�2flfi ;142. 5 16 10,QIV6 X2iA6 Tbg k4 OA OQA —0. T 10 &d S.w;k-. Ovb—d j C— VA. x MnO/2DI4 y 4,742 Well S-41A Injection Plot 78,", 16000 1a;ta>L 13(W, 120w 11.000 1Qcai 4.U00 sow "UO &we 3 wG 3.00G 2 O. I OLO l.iRkl —WHIP SVI — PP( — MI 6.000 —(Wier On S 000 40M 3.000 Do. Sf /&ui 07/14/2014 7/W2016 '', Rdoed Pk4 ky Cad lag Scab To CSpb—d Cu Vakm X 0 WQ2014 v 1779/ TTiEE= 4-V16"C1w VAal+EAD = FMG ACTUATOR = BAKERC' OX8_ ELEV = 71,7 W HI-V= 3r KOP- tt31`" Alex Angle = W @ 14W3 DoMm MD = 1184-T DeMum TVD = 8800, SS' I1-&V CS+G, 40N, L-80 BIQTT, D - 8 835" 7- GW,, 7w. 1 -80 t3TC.. 0363 bol, D a 6.:2T6' Minimum K) = 3.726" @ 11916' 4-1t2- HES XN NIPPLE 3332' MN.I.OUT WS�IDCAM (5-41 L1) 11892' • 1 ilOS� St UBEIMOFFOWM10 S-41 A La1 RA PPTAG H 11782' t IrZ TBG 12 69 13CR 86 V AM TOP, 1196 .0152 bpf, D= 33958' -OPOF 4- Ur LNR 119S T CSC, 29#, L-80 BTGhA .0371 bp1, D = 6. t84' -- -120 PEFGXMT)J:J S'CIMAKRY REY LOG- SL8 MAVUR ON 09MV10 f....�,,. ,...-ram. �. qy � ibis W fef is Roduct on DB fpr Festorica.l pert data SIZE I SIV I INTERVAL 1 Opn/Sqz DATE 3-41A 2418' 6 12700 13100 O ICY09110 3 2-71117 6 13200 - 136W 0 1(VO9110 2-7 6 137M - 14100 0 10109110 2-7W 6 14ZO - 14350 0 11YOW10 2-7/8 6 14940- 1$150 0 10f09110 3-41AL1 4-1 SLTD t1947- 11902 SLOT 1CY16H0 4-1 SLTD 1 12301 - 135M8 SLOT 10118110 SAFETYIDTBB WILL AMXEa70'M1Il12OW-4-Irr CHi011E T80 i LIB"' 222T I-j4.lrFe8XNP,D=3.61: C'.AC 167 km Pimp S. ST LID I TVD I DEV TYPE VLV LTCJfi PORT DATE 5 3742 3331 48 KBG-2 OMY BK 0 03MW14 4 7112 SW 47 KBC-2 DMY BK 0 03NM14 3 9705 7345 47 KBCr2 OW BK 0 03M14 2 11639 8777 65 KBG-2 -OMY BK 0 11117/15 1 111808 SM 64 KBG.7 10ti1Y SK 0 owl 3111 STA 91 IS SOW PKR ENABLE TO USE FORGL $TA 02 - EXTBCM PACKING 11873- I- + lf1 ' HES X f4P. D = 3.813 l 7' x 4- IlY W3 TNT MR D = 3.858' (4-VrHMXNP.D=3.813' I 11�-14-11Y If.S XC CURD SLO SLV, 10 - 3.8137 11916' l,4+1:2- FE5 XN HP. D = 3.725' MLLOVT WFCQWIti41AL11 11926'- 11939 11941T 1&0+ H C.AL cur SLOTTED LINER ---------- ----------- S-- 4-112' $LTD LI4R 12,00, L-WIST-At H 13M' 0152 W. D= 3 968' OPk3Y 1itlL1 1S2ST 11l51' 4•VIBKRTl[DACK A53Y.ID-4.30' --'11964' T 7X S 1'/'><t C ZJ1F�t DTP w t FBR O a 4.20- 11976'-xS5KRF>IXLOCKLhRF46 D=4.220'I 11986 5' X 4-11Z' XO D = 3.92(r G M11 CxtTYrwf'DOW (S-4tAj t2OOl3 - iZO'1i 13360' 4-1r1' RA TAG LN,126A13CR-86VAMTOPWVbpl.IJ 3,95S H IS41T DAlt REV BY I C01r EN4T`' ORATE ! ITV BY I COMMEWS 04MON NnE ;ORIGINAL COMPLETION 11125115 14Ci7JW GLV C4001117H5i 10f23M10 N?ES :SKXTRACIC(SAIAIAL1) 06tiStt1 MQPJC FNALDRLGCL7RPECT1CMi5 08115n 1 ALFY P GLV CYO (611311/ ) _ OBI16111 ALI V -P FULL Px- Pi UG 10&13/t t ) 03t11,14 RKTtJMD GLV CIO (03W14) P1 MIDE BAY UMT WH. I FS 41A f At.1 FTJW W: 2101010 (20) AR No: 506029-Z2645-01 (81) SEC 35, T121y R12E 1128' FW 8 775' PM- BP INPIwalloo (AlUll(al 11 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: jim.regg(aialaska.gov; AOGCC.Inspectors(a)alaska.gov; phoebe.brooks(dalaska.gov chris.wallaceCdalaska.aov OPERATOR: BP Exploration (Alaska), Inc. FIELD I UNIT I PAD: Prudhoe Bay / GPB / W-Pad DATE: 01 /26/16 OPERATOR REP: AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well W-24 I Type In'. I W TVD 1 8,531' Tubingi 1,289 1,289 1,289 1,288 1 1 Interval p P.T.D. 1880700 I Type test I P Test psi 2132.75 Casingl 51 2,500 2,479 2,471 P/F P Notes: MIT -IA to evaluate for Admin Approval OA 4 17 17 17 5.4 bbls AMB DSL to reach test pressure; 3.8 bbl bled back Well I Type In'. I TVD I Tubing Interval P.T.D. I Type test I Test psi I Casing P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well I Type In'. TVD I Tubing Interval P.T.D.1 I Type test Test psi I Casing P/F Notes: OA TYPE INJ Codes D = Drilling Waste G = Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11 /2012) MIT PBU W-24 (PTD # 1880700) Jan 2016 MIT -IA arrd Feb 2016 MIT-OA.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: AOGCC.Inspectorso)alaska.gov: phoebe.brooks(a)alaska.gov chris.wallaceCabalaska.gov OPERATOR: BP Exploration (Alaska), Inc. FIELD I UNIT I PAD: Prudhoe Bay / GPB / W-Pad DATE: 02/12/16 OPERATOR REP: AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well W-24 I Type In'. I N TVD 1 8,531' Tubing Interval O P.T.D. 1880700 I Type test I P Test psi 2132.75 Casing 77 79 80 80 P/F P Notes: MIT-OA to evaluate forAdmin Approval OA 1 1200 1136 1117 4 bbls AMB DSL to reach test pressure; 0.3 bbl bled back; tubing was on a vac during test Well I Type In'. I TVD Tubing Interval P.T.D. I Type test I Test psi Casing P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D.1 I Type test I Test psi Casing P/F Notes: OA Well I Type In'. I TVD I Tubing Interval P.T.D. I Type test Test psi I Casing P/F Notes: OA TYPE INJ Codes D = Drilling Waste G = Gas I = Industrial Wastewater N = Not Injecting W = Water TYPE TEST Codes M = Annulus Monitoring P = Standard Pressure Test R = Internal Radioactive Tracer Survey A = Temperature Anomaly Survey D = Differential Temperature Test INTERVAL Codes I = Initial Test 4 = Four Year Cycle V = Required by Variance O = Other (describe in notes) Form 10-426 (Revised 11 /2012) MIT PBU W-24 (PTD # 1880700) Jan 2016 MIT -IA and Feb 2016 MIT-OA.xls Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com> Sent: Wednesday, March 09, 2016 5:33 PM To: Wallace, Chris D (DOA) Cc: AK, D&C Well Integrity Coordinator, Sternicki, Oliver R Subject: Injector W-24 (PTD #1880700) Additonal Administrative Approval Information Chris, As requested, Injector W-24 (PTD #1880700) is one of the higher value patterns for MI injection and a well that the BP reservoir team would like to utilize for future MI. Producer W-18A (PTD # 2130810) was recently drilled within the MI pattern of Injector W-24 and has only seen one slug of MI. This offset producer would benefit from approved WAG injection in Injector W-24. The currently injection for MI is at 22% hydrocarbon pore volume (HCPV**) and the current target is to inject up to 35% HCPV depending on the results of MI in this pattern. If results of future MI slugs are found to be favorable, an additional 6 billion cubic feet (BCF) of MI will be injected into the pattern. The future slugs would be spaced out so that Injector W-24 would inject 6% HCPV of MI followed by an equal amount of water. Infection History: • Current injection volumes : 11 Bcf of MI , 5.59 MM Stock Tank Barrels (Stb) of water • HCPV basis: 22.2% HCPV of MI and 16.3% HCPV of water • Current water target: 5000 bwpd • Projected swap to MI if water target is met: April 2017 • April 2017 will design a swap where the HCPV of water injected matches the HCPV of MI • Predicted MI potential: 2 additional MI slugs (3 Bcf each) ** The Hydrocarbon Pore Volume or (HCPV) is comparing the amount of MI or Water injected in a pattern to the estimated original oil in place volume (OOIP). It is the ratio of the MI/OOIP or the water/OOIP to come up with a % HCPV. The units for both MI and OOIP or Water and 001P are in reservoir barrels so that they can be compared on an equal basis. Annotated Well History & Pressure Falloff Data: E=1212 Wn Timeline scale: 01/09/16 — 03/09/16 (2 months) • No bleeds have been performed in 2016. Pressure was left on the Inner Annulus (IA) following an MIT -IA performed at the end of January. A MIT-OA was then performed mid February with pressure was left on the OA at the end of the test. • 01/26/16: MIT -IA to 2500 psi performed (Passed), final wellhead pressures TBG/IA/OA = 1290/400/0+ psi • 02/12/16: MIT-OA to 1117 psi performed (Passed), final wellhead pressure TBG/IA/OA = VAC/80/770 psi 2 Well. W-24 r, ,-.- .-.... , f 41 ►y ti ry e. ........................ Timeline scale: 10/09/15 - 03/09/16 (6 months) • 10/17/15: Increase IA pressure, final wellhead pressures TBG/IA/OA = 1380/500/20 psi Please let me know if you have more questions, comments, or concerns. Thank you, Whitney Pettus (Alternate: Kevin Parks) BP Alaska - Well Integrity Coordinator GW WIC Office: 907.659.5102 WIC Email: AKDCWelllntegrityCoordinator@BP.com 10 BP Exploration (Alaska) Inc. Douglas A. Cismoski, P.E., BPXA Wells Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 March 7, 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 RECEIVED by MAR 0 7 2016 0 AOGCC Subject: Prudhoe Bay Well W-24 (PTD # 1880700) Request for Administrative Approval to Continue WAG Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval for continued WAG injection operations into Prudhoe Bay Well W-24 (PTD # 1880700). W-24 exhibits inner annulus pressure falloff of —11 psi/day while on water injection. UIC required differential pressure between the IA and OA cannot be maintained without frequent interventions. A pressure test of the inner annulus to 2500 psi on 01/26/2016 passed. A pressure test of the outer annulus to 1200 psi on 02/12/2016 passed. These tests indicate that the tubing and production casing are competent. Inner and outer annulus operating pressure is maintained below the maximum allowable pressure limit. Consequently, no repairs are planned at this time. In summary, BPXA believes Prudhoe Bay Well W-24 is safe to operate as stated above and requests administrative approval for continued WAG injection operations. If you require any additional information, please contact me at 564-4303 or Kevin Parks/ Whitney Pettus at 659-5102. Sincerely, _��W4 Z-11- - Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments: Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks GC2 Operations Team Leader Kaity Burton Ryan Daniel Prudhoe Bay Well W-24 Technical Justification for Administrative Approval Request March 7, 2016 Well History and Status Prudhoe Bay Well W-24 (PTD # 1880700) exhibits inner annulus pressure falloff while on water injection. A recent MIT -IA and MIT-OA passed, demonstrating competent tubing and production casing. Inner and outer annulus operating pressure is maintained below MOASP. Recent Well Events: >02/12/16: MIT-OA Passed to 1200 psi >01/26/16: MIT -IA Passed to 2500 psi, PPPOT-IC passed to 3500 psi >11/25/15-1/26/16-. IA pressure fall off rate-1 1 psi/day Barrier Evaluation The primary and secondary barrier systems consist of tubing and production casing and associated hardware. Pressure testing of the inner annulus passed to 2500 psi, demonstrating competent primary and secondary barrier systems. Proposed Operating and Monitoring Plan 1. Record wellhead pressures and injection rate daily. 2. Submit a report monthly of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA to maximum injection pressure. 4. Maintain the inner and outer annulus operating pressure below MOASP. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. W-24 TIO Plot 4 L", 25W 2 OM Y-, 24 —10 P1,1 W-24 Injection Plot -4-- Tbg LA OA OOA OOOA 0a 1�1. S.SW O"I'M14 flabad Flat TIO end "pb"w C� VakA X 12/"13 y 3.393 C— Vd- * 12415/M3 * 3245 tio Wv rLZ1 VYELLWAD= WEVOY AcnA-roR= BAKER C OK& ELEV = 87 4El'EV - 53 90� KOP 6607 Max Angle = so- a "W —9 Datum MA - 2 3 M P" P,/D= 13-3fr �Minimum 6 4-112" OTIS XN NIPPLE LL I r2" 4-1)2* W-24 Schematic SAFETY NOTES, H2S HEADINGS "EMOE 126 ppm W -2 4 WHEN ON Mi. WELL MQUIRES A WSYSAtEry ALO TE 21W t 9711' L8,73r Hllq:HBS X NP. D - 3.813" Hg-sw X 4.117 87577 w- HEs x Nip, iD = iaiw �4-10' X �S-lrT )00, �V� 3 95�W LIL -;,� � = — M =—===1yf-AEi FERFORATIONSULSARY REF LOG SUMS-BHCS-GR ON OW13f$B. SWS CBT ON 08MW ANGAEAT TOP MRF--4ro921Z Note. Awfer bD Pnxkcbon OB for WkWrW parf data SVE SW KFERVAL OpNSqz DUE 2- 1 Qr 6 9212-9264 0 ostl W5 2- fir 6 9244 - 9264 0 03,W12 338' 4 9274 92W 0 06118/96 2-71W 6 9274-9290 0 03rM12 S, 17 W7%. - CM7 R ("MM 2-T18r 6 929E.9330 0 03129f12 3-3fW 4 9303-9330 0 cwlamA 2-71W 6 9333-9346 0 03rM12 3-316* 6 9333- 9346 0 09114195 3.XW 6 9351- 9358 0 OWUM 3-3f8' 6 9371 - 91379 0 09/141% 3-3(W 6 9595 - 9415 0 10w91 5" 6 943D - 9454 s 09m1i91 51 12 9506-9514 S 09MI190 GAS LFr MANDRELS 8868' H4-U2"PARKERSV4SWlO=3,813' 8874' f" � 9-98' X 4 lrr OTIS "C FKR. ID = 3.4 Mr �-��Ir--PARKERSMNPID=3.81T mr k44-l-r---w-u-q-3—JD=3--958'-1 7'UAFVaRJOKr 9218- FISH - SHNNER. W—A Pill fHJDHOE BAY LUT WELL W-24 FEFUT Na: *I aWT[)O API No: 50-029-21833-00 %2C21, TIIN R12F- 521'FNL & 1179 Fa SP BqAoradon (Alaska) • Dave Lachance Vice President Alaska Reservoir Development September 8, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com SEP 0 8 2015 Re: Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Written Response to Commission Requests Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, the enclosed written response to Commission requests directed to BPXA during the hearing on August 27, 2015. Please note that the portion of our response contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. The Confidential Appendix is enclosed in a separate envelope and marked confidential. S' cerely, Dave P. Lachance Vice President, Reservoir Development Attachment BPXA Post -Hearing Respons• Commission Requests Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP 0.brian.gross@exxonmobil.com) Jon Schultz, CPAI(Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) RECEIVED • SEP 0 8 2015 AOGCC AOGCC Docket Numbers: AIO 15-032, AlO 15-033 and CO 15-09, Prudhoe Oil Pool Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Post -hearing Response to Commission Questions INTRODUCTION At the hearing on August 27, 2015, on the referenced application by BP Exploration (Alaska) Inc. (BPXA) to the Alaska Oil and Gas Conservation Commission (AOGCC or Commission), the Commission asked BPXA to submit, post -hearing, responses to Commission requests for the following: 1. Analysis of a full field model (FFM) run or runs depicting the optimal start-up time for Prudhoe Oil Pool (POP) major gas sales (MGS) that is indifferent to specific project considerations; and 2. Analysis of a FFM run depicting the point in time when the BTU value of fuel gas usage is greater than the BTU value of the oil it's producing. (BPXA interprets this request by the Commission as a request for a comparative analysis of incremental oil recovery and incremental fuel gas usage resulting from pushing back the start-up of major gas sales, expressed in barrels of oil equivalent.) This submittal addresses each of these requests. OPTIMAL MGS START-UP DATES INDIFFERENT TO SPECIFIC PROJECT CONSIDERATIONS NTRODUCTION The classic petroleum engineering text book approach to greater ultimate recovery of an oil field with an original gas cap is to first target the oil for development while re -injecting the produced gas to maintain reservoir pressure. In this text book approach to hydrocarbon recovery, it is only after oil production is no longer economically viable that the gas is produced from the reservoir and sold. The logic behind this text book approach to hydrocarbon recovery is that if gas is sold too early the reservoir will lose pressure before oil production is optimized, and as a result total hydrocarbon recovery will be less than otherwise. This is how development of the POP has proceeded for 38 years. The POP has recovered significantly more oil than it would have without gas re -injection. However, the POP is entering a stage in which this simple text book approach to hydrocarbon recovery no longer reflects the complexities of POP development. That's because field development needs to consider several significant factors uniquely applicable to the POP: (1) availability of necessary infrastructure to support a gas export project; (2) fuel gas consumption, (3) facility life considerations; and (4) that the POP has acted similar to a gas field for more than two decades. For example, in a scenario in which a gas export project is available before oil development becomes un- economic, but would not be available at a later date, greater ultimate hydrocarbon recovery can only be achieved by proceeding with gas sales. The Alaska LNG Project is moving forward on a timeline targeting gas production for major gas sales from the POP potentially in 2025. There are no other gas sales projects proposed for sales of POP BPXA Post -Hearing Submission Page 1 of 7 gas sooner than that date or at a later date. Since oil production and gas re -injection consumes fuel gas that could otherwise be sold and contribute to hydrocarbon recovery, by adjusting for fuel gas consumption, if a major gas sales project moves forward in 2025 greater ultimate recovery will likely occur through gas sales prior to oil development becoming un-economic. POP operations currently consume —400 MMSCFD, or approximately 25 million barrels oil equivalent (BOE) per year, of fuel gas to sustain oil production, whereas fuel gas requirements will be substantially reduced during major gas sales. As facilities age, equipment performance and reliability are factors that can impact production and ultimate hydrocarbon recovery. Oil production began from the POP in 1977 and with a MGS start-up in 2025 much of the Prudhoe Bay Unit production facilities will have been in operation for 50 years. Additionally, the landscape of existing supporting infrastructure and delivery systems is likely to change with time. The Commission's approval of BPXA's application in this matter is a necessary and critical step in trying to make POP major gas sales, through a large project such as the Alaska LNG Project it would support, successful. SUMMARY AND CONCLUSIONS Depending on the assumptions that are made, ultimate hydrocarbon recovery from the POP could potentially increase by up to 100 million BOE (MMBOE), less than 1 % of ultimate hydrocarbon recovery, if a comparable MGS project were to commence operations in 2040 rather than 2025 in the reference case. This is premised on the assumption that a POP MGS project is available at that time and advances, and that all necessary facilities, infrastructure and delivery systems have the same remaining capability at project start-up as the 2025 MGS reference case. However, there are unknown factors that could significantly undercut these assumptions including that a MGS opportunity may not be available, which would reduce overall potential hydrocarbon recovery by approximately 3.6 billion BOE. As mentioned, the Alaska LNG Project timeline targets potentially beginning operations in 2025 and if so then gas sales from the POP are estimated to total 22.4 TCF of gas, increasing ultimate hydrocarbon recovery from the POP by between 3.5 and 3.6 billion BOE. Even though there is a potential for slightly greater hydrocarbon recovery with a later MGS date, the complexity and significant financial commitments required to advance a MGS project of this magnitude and the risk of significantly lower ultimate recovery more than offset any potential gain. A later MGS start-up also increases the uncertainty that the project can deliver a full 30-year project life due to declining oil production and revenues which underpin the project, and due to increasing project risk from aging facilities which could reduce project life and thus ultimate recovery, reducing the potential incremental recovery relative to a 2025 start-up. A. BPXA'S FFM RUNS ASSUMPTIONS AND RISKS BPXA (as an individual working interest owner and not as operator) used its proprietary FFM tool (FFM Tool) to build FFM runs to assess the impact of starting MGS from the POP within a range of start-up dates: 2025, 2030, 2035 and 2040. BPXA used the following assumptions in running each case: BPXA Post -Hearing Submission Page 2 of 7 • Assumption: A project similar to the current AK LNG project is available to start-up at each of the different 5 year increments. Risk: A gas sales project is not available for POP major gas sales at a later date. Therefore, any additional recovery that may be assumed to be recovered by pushing back the start date for a project (<0.1 billion BOE), must be balanced against the risk of not recovering any of the gas (>3.5 billion BOE). • Assumption: All PBU oil and gas process facilities and TAPS are fully available for oil transportation and gas production for the length of the total production period with a 30 year MGS project period in all cases. Risk: Facilities used to produce the oil and gas will age over time and typically operate outside optimum design basis parameters, reducing the ability to recover the oil and gas indicated in the profiles. While the FFM runs account for well breakage and repair, it does not account for impacts due to facility or pipeline availability or performance, including TAPS.' As the facilities age, it is more likely that major equipment performance and reliability will affect oil and gas production. Directionally, there will be an increasingly greater impact on the gas sales cases with later start-up dates. The production profiles provided are not adjusted for any performance reduction factors associated with later major gas sales dates. 2. MODEL RUN PROFILES a. GAS DELIVERIES PROFILES The POP gas sales profiles (excluding COz) for the 2025 (Reference Case), 2030, 2035 and 2040 start-ups are shown in Figure 1 in the Confidential Appendix to this submittal. The shape of these gas delivery profiles are similar, however, as start-up dates are extended, the plateau length decreases, from 21.0 to 19.6 years. The cumulative amount of gas delivered for sales decreases with each increment of extended start-up, from 22.4 TCF (2025 Start-up) to 20.9 TCF (2040 start-up), due to increased fuel gas consumption (see Table 1). b. OIL PRODUCTION PROFILES The POP liquid hydrocarbons (oil + NGLs) profiles for the oil reference case, and the 2025 (gas reference case), 2030, 2035 and 2040 start-ups are shown in Figure 2 in the Confidential Appendix to this submittal. Due to the drop in reservoir pressure at the onset of gas sales, oil production profiles correspondingly decline at a faster rate at the onset of gas sales, followed by a period of slower rate of decline. Liquid hydrocarbon recovery for the various cases is detailed in Table 1 and Table 2. c. FUEL GAS USAGE PROFILES Fuel gas is mainly consumed in the POP to generate electricity, heat fluids and facilities, pump fluids, and most significantly, compress the dry residue gas for reinjection. When gas sales begin from the POP, fuel usage will decrease as less compression is needed to send gas to the GTP rather than to re -inject the gas. As reservoir pressure declines and active well counts decrease over time, less fluid will be heated, pumped and compressed, and fuel usage will decrease further. These effects are accounted for in the FFM run forecasts of fuel gas usage shown in Figure 3 in the Confidential ' The FFM Tool is capable of performing this analysis, but BPXA has not run such cases. BPXA Post -Hearing Submission Page 3 of 7 Appendix to this submittal. The figure shows that a later start of gas sales results in higher total fuel usage. Once gas is used for fuel it is no longer available for gas sales; therefore, later start of major gas sales results in lower gas sales volumes. Total Hydrocarbon Profiles Figure 4 in the Confidential Appendix to this submittal shows oil and gas sales profiles combined into total hydrocarbon BOE profiles, assuming 1 barrel of oil is equivalent to 5.8 thousand standard cubic feet (MSCF) of gas. The POP BOE rate profiles in Figure 4 are the same as the oil reference case until the start of major gas sales, when total BOE production increases dramatically. Although gas sales rates are on plateau for approximately 20 years, total BOE delivery declines over that period due to declining oil production rates. At the end of the major gas sales plateau period, total BOE delivery rates drop more rapidly as both oil and gas sales rates are declining. B. ASSESSMENT OF ULTIMATE RECOVERY 1 . END OF FIELD LIFE Two methods to evaluate the end of field life (EOFL) were used in this study to evaluate ultimate hydrocarbon recovery: 1. Common gas sales project length 2. Common minimum total hydrocarbon production rate Ultimate hydrocarbon recovery for the suite of MGS start-up dates sensitivities are evaluated against each of the EOFL methodologies. 2. FULL FIELD MODEL PRECISION The resolution of the model is —+/- 10 Million barrels of oil recovery, and —+/- 30 Million BOE on gas sales, and —+/- 40 Million BOE of hydrocarbon recovery. FFM model precision was determined by running a series of simulation runs that were identical, except for a small perturbation to the inputs. The model precision quoted was determined from the range of this series of results. If simulation results from model runs of different scenarios are within these ranges of recovery, the impact of the sensitivity is not discernible from the uncertainty, and should not be used to inform decisions or rank scenarios. 3. UNACCOUNTED FOR RISKS TO ULTIMATE RECOVERY The following analysis does not account for two significant risks. These risks have a greater probability of occurrence as a MGS project start-up extends beyond 2025. 1. A major gas sales project may not be available to ship gas from POP at a later date. Therefore, any additional recovery that may be assumed to be recovered by a later project (<0.1 billion BOE), must be balanced against the risk of not recovering and selling any of the gas (>3.5 billion BOE). 2. Facilities used to produce the oil and gas will age and operate outside of the maximum efficiency range which could affect performance and reliability over time, reducing the ability to recover both the oil and gas indicated in the profiles. Infrastructure and delivery systems BPXA Post -Hearing Submission Page 4 of 7 could also impact oil and gas deliverability later in POP field life. While the FFM Tool and the cases run by BPXA account for well breakage and repair, they do not account for impacts due to facility or pipeline availability or performance, including TAPS.2 Directionally, however, it is safe to say that there will be a disproportionately greater impact on the gas sales cases with later start-up dates. C. ULTIMATE RECOVERY COMPARISON 1. RECOVERY AT A COMMON PROJECT LENGTH Table 1 shows the recovery of oil and gas, fuel usage, and total hydrocarbon recovery assuming a 30- year MGS project life; for example, the 2025 start-up case has an EOFL in 2055 and the 2040 start-up case has an EOFL in 2070. The EOFL of the Oil reference case is 2055. The table shows that hydrocarbon recovery is fundamentally maximized by achieving an MGS project, as the remaining hydrocarbon recovery from 2025 forward increases by more than four -fold for all MGS scenarios relative to the Oil Reference case. Among the MGS scenarios, the table shows that oil recovery increases, with greater fuel gas consumption and less gas sales, with a later MGS project. In addition to greater oil recovery prior to start of major gas sales, additional oil recovery is achieved on the tail of the profile due to possible field life extension. This additional oil recovery is balanced against the additional fuel consumed during the oil production period and on the tail. These results assume that wells and facilities will last for the duration of production in each scenario. These un-risked recovery profiles show that the increase in ultimate total hydrocarbon recovery with later start-up of major gas sales from 2025 to 2030 is about 0.05 B BOE or 50 MMBOE. Extending the start of major gas sales from 2025 to 2040 increases total hydrocarbon recovery by approximately 0.1 B BOE or 100 MMBOE. A volume of 100 MMBOE is only about 0.5% of the total expected hydrocarbon recovery. TABLE 1: UNRISKED RECOVERY OF OIL, GAS, FUEL AND TOTAL HYDROCARBONS FROM THE POP FROM 2025 TO 30 YEARS AFTER THE MGS START-UP, SENSTIVITIES TO PBU MGS START-UP DATES. Unrisked Recovery from 2025 to 30 years after MGS Start -Up Case Oil Gas Sales Fuel Gas Total Hydrocarbons (Billion STB) (TCF) (TCF) (Billion BCE) Oil Reference 1.07 - 3.68 1.07 Gas Reference - 2025 MGS 0.79 22.43 2.40 4.65 2030 MGS 0.93 21.92 3.08 4.71 2035 MGS 1.05 21.35 3.61 4.73 2040 MGS 1.14 20.96 4.15 4.75 2. RECOVERY AT A COMMON TOTAL HYDROCARBON RATE Assessment of EOFL at a common total hydrocarbon production rate is often used to estimate the economic life of a project. The ultimate hydrocarbon recovery is determined by assessing the 2 As noted earlier, the FFM Tool is capable of performing this analysis, but BPXA has not run such cases. BPXA Post -Hearing Submission Page 5 of 7 0 0 cumulative hydrocarbon recovered at the same total hydrocarbon rate for each case, instead of a fixed date. The cut-off rate assumed for this evaluation is 100 MBOE/D, and does not represent BPXA's view of the actual field economic limit which will depend on oil and gas prices and other future economic conditions which cannot be accurately predicted now. This total hydrocarbon rate is consistent with the rate limit used in the 2007 Blaskovich report commissioned by the AOGCC. Figure 5 in the Confidential Appendix to this submittal shows the total hydrocarbon production rate as a function of the total cumulative hydrocarbon recovery. The optimal recovery case is the one achieving the highest cumulative recovery at a given cut-off rate. However, Figure 5 indicates that after the field comes off plateau, the recovery curves lie on top of each other. This means that after gas plateau ends, the cases have similar ultimate hydrocarbon recovery for almost any common hydrocarbon production rate cut-off. Table 2 shows the recovery of oil and gas, fuel usage, and total hydrocarbon recovery assuming a common hydrocarbon rate cut-off of 100 MBOE/D. The data indicates that oil production is greater with MGS than the oil reference case by about 60 million barrels (MMbbls) using the common rate cut-off, rather than -280 MMbbls with a common end date, due to a significant extension of field life. The data in Table 2 also shows that the maximum difference in ultimate hydrocarbon recovery between the 2025 start-up case and other cases is 70 MMBOE, which approaches the resolution of the model for total hydrocarbon recovery (—+/- 40 MMBOE), without making any adjustments for facility life and project availability risks. According to the common total hydrocarbon rate EOFL metric, there is little discernible difference in total hydrocarbon recovery between the different MGS start dates cases, within the resolution of the FFM runs. TABLE 2: UNRISKED RECOVERY OF OIL, GAS, FUEL AND TOTAL HYDROCARBONS FROM THE POP FROM 2025 TO 100 MBOE, SENSTIVITIES TO PBU MGS START-UP DATES. Unrisked Recovery from 2025 to 100 MBOE/D Cut -Off Case Oil Gas Sales Fuel Gas Total Hydrocarbons (Billion STB) (TCF) (TCF) (Billion BOE) Oil Reference 0.72 - 1.91 0.72 Gas Reference - 2025 MGS 0.78 22.16 2.35 4.60 2030 MGS 0.93 21.72 3.04 4.67 2035 MGS 1.05 21.03 3.55 4.68 2040 MGS 1.13 20.35 4.03 4.64 II. OIL RECOVERY VERSUS FUEL GAS USAGE Using the data in Table 1, the comparative incremental oil recovery and incremental fuel gas burned by pushing back the start-up of MGS, can be approximated. Figure 6 shows that the incremental oil recovered by a later start of MGS from 2025 to 2030 is —140 MMBOE, and the corresponding additional fuel burned is about —120 MMBOE. If POP MGS start-up occurs from 2035 to 2040 the BOE increase in fuel gas consumption surpasses the additional oil recovery. BPXA Post -Hearing Submission Page 6 of 7 4,000,000 3,500,000 3,000,000 LU O m 2 2,500,000 Z 2,000,000 v 1,500,000 1,000,000 160,000 140,000 120,000 0 m E 100,000 e 2 $0,000 m .9 60,000 3 40,000 20,000 500,000 PBU MGS Recovery 2025 to 2030 Incremental Recovery Due to five Year Delay of MGS ■ Oil ■Fuel (BOEI T PBU FFM 1 uncertainty 2025 to 2030 r 2030 to 2035 2035 to 2040 FIGURE 1: INCREMENTAL OIL RECOVERY AND FUEL GAS BURNED BY EXTENDING THE START OF MGS FOR FIVE YEAR PERIODS. ERROR BARS REPRESENT PRECISION OF FFM RUN PREDICTIONS FOR ULTIMATE RECOVERY. BPXA Post -Hearing Submission Page 7 of 7 p BP Exploration (Alaska) Inc. 900 E. Benson Boulevard Anchorage, AK 99508 P.O. Box 196612 Anchorage, AK 99519-6612 September 8, 2015 Via Hand Delivery REMOVED Cathy P. Foerster SEP 0 8 2015 Commission Chair A O�VC Alaska Oil and Gas Conservation Commission A 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Re: Docket Numbers: AIO 15-032 AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Comment to Commission regarding a Sunset Provision Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits the following comment for the Commission's consideration in this matter. The Commission's announcement during the hearing on August 27 that it is inclined to include a Sunset provision in its final order in this matter came as a surprise and source of concern for BPXA and Exxon Mobil. While our companies are aware of similar provisions in some parts of our lower 48 operations', the inclusion of a Sunset clause in an AOGCC Order for a pool rule order approving the request for a modification to the existing gas offtake rate is unprecedented and would undermine the certainty of supply from the Prudhoe Bay field that is needed to progress the Alaska LNG Project by BPXA, the State of Alaska, and the other parties. As we testified at the hearing, the Alaska LNG project is not expected to begin operations until approximately 2025. The reason a rate increase is being requested at this time is to provide certainty of supply amongst the parties, the export market, and the lending community. An order with a limited term -of any duration could significantly hinder the progress of the Alaska LNG Project because the long-term basis for gas sale contracts would be uncertain. As we presented in both the written materials and verbally during the hearing, the best way for the Commission to help ensure greater ultimate recovery of oil ' For example, it is not uncommon in states similar to Kansas for its Conservation Commission Orders to include a termination clause such as the following in its orders: "This Order shall remain in effect until amended, changed, or modified by order of the Commission." However, a more specific Sunset provision generally would be based on operational considerations versus a simple time limit. For instance, certain Orders might terminate "at that point in time when no remaining well in the field is capable of producing in excess of 'Y' Mcf/d of gas or "y" bbls/d of crude oil, unless modified by further order of the Commission to terminate sooner". BPXA Post -Hearing ComOnt to Commission Regarding a Sunset Claus• Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 and gas from the Prudhoe Bay Unit Prudhoe Oil Pool is to exercise its statutory authority to facilitate the project moving forward to the fullest extent possible. Moreover, it is important to note that the inclusion of a Sunset provision in the Commission's order is not necessary because the Commission has the existing statutory power to call an investigation to re-evaluate any existing Order and either issue an emergency suspension of that provision or undertake a full hearing on the issue. Therefore, inclusion of a Sunset clause would provide little or no benefit to the Commission at the considerable cost of stifling certainty for long-term gas supply commitments. Sincerely, iol_ Da e Va uyl Regional Manager BP Exploration (Alaska) Inc. • Dave Lachance Vice President Alaska Reservoir Development September 8, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachanceGbp.com RECEIVE SEP 0 8 2015 AOGCC Re: Docket Numbers: AIO 15-032 AIO 15-033 and CO 15-09, Prudhoe Oil Pool BPXA Post -Hearing Submission of Redacted Confidential Presentation for Public Record Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc. (BPXA) submits, on behalf of itself and ExxonMobil Production Inc., as applicants in the above referenced matter, the enclosed redacted version of BPXA's confidential presentation to the Commission during the hearing on August 27, 2015. The enclosed presentation has been redacted to remove confidential data, consistent with our discussion with the Commission during the hearing, so that it may be included in the public record in this matter. Si cerely, Dave P. Lachance Vice President, Reservoir Development Attachment BPXA Post -Hearing Submis3"!on of Redacted Confidential Presentation fo�ublic Record Application to Amend POP Rule 9 and Modify AIOs Page 2 September 8, 2015 cc via email: Ernesto Daza, BPXA (ernesto.daza@bp.com) John Dittrich, BPXA Oohn.dittrich@bp.com) George Lyle, Guess & Rudd (glyle@guessrudd.com) Chris Wyatt, BPXA (chris.wyatt@bp.com) Gilbert Wong, EMAP (gilbert.wong@exxonmobil.com) Gerry Smith, EMAP (Gerry.b.smith@exxonmobil.com) Steve Luna, EMAP (charles.s.luna@exxonmobil.com) Brian Gross, EMAP 0.brian.gross@exxonmobil.com) Jon Schultz, CPAI(Jon.Schultz@conocophillips.com) Eric Reinbold, CPAI (Eric.W.Reinbold@conocophillips.com) John Evans, CPAI (John.R.Evans@conocophillips.com) Phil Ayer, CUSA (pmayer@chevron.com) Angie Bible, CUSA (abible@chevron.com) Redacted Version for Public Record b CONFIDENTIAL PRESENTATION The data in the following presentation contains BPXAs own engineering, geological and geophysical analysis and interpretation of PBU data, as well as other sensitive commercial information. BPXA requests that this information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq., as well as Section 11.4 of the Prudhoe Bay Unit Agreement. (Please note that the slides also include some non - confidential narrative carried over from the public session for presentative purposes.) RECEIVED SEP 08 2015 z i /August 1U-1 b • Support Rule 9 Application for amendment of CO 341 D Rule 9 for the Prudhoe Oil Pool(POP) i Technical justification for increasing the maximum allowable gas offtake from 2.7 to 4.1 BCFD Address several topics of interest for the AOGCC Support Application for AlO Modification of AlO 3A and AlO 4F Technical justification for request to inject CO2-byproduct into the POP for Enhanced Recovery and Pressure Maintenance bp The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years -- Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic • feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access of the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved Parallel, Compositional VIP Model Integrated subsurface, well, pipeline and facility model World class history match from 1977 to Present Examples of Uses: Facility optimization Activity planning Lean and Miscible gas injection Gas Cap Water Injection (GCWI) Gas Sales Development planning Redacted Confidential Information )n Ell 1) Oil Reference Case a) Active development drilling program b) Rig workovers for well repair c) Continued Gas Cap Water Injection (GCWI) d) Normal annual TAR events and facility downtime 2) MGS Reference Case and MAG Sensitivity Case a) Same drilling program as Oil reference case b) Rig workovers for well repair c) Continued Gas Cap Water Injection (GCWI) d) 1/1/2025 gas sales startup with a 1 year ramp e) Annual average sunnly to AKI NC; rTP lnlzt IXA/U`n01• MGS Reference Case �MAG Sensitivity Case 2.7 BCF/D 3.6 BCF/D f) Normal annualTAR events and facility downtime g) GTP by-product (CO2) injected into Eileen West End (EWE) h) Convert apex gas injectors to producers i) Add gas perforations j) Project length 30 years 5 • • Oil Reference Case - POP Oil and Production Forecasted liquid volumes reflect ongoing development activity Field production continues to decline with substantial development and optimization Recovery approaches 4.5 billion stb's more than originally predicted in 1977 of 9.7 billion stb's 6- 0 Redacted Confidential Information I 0 no by POP Voidage (Oil, Water, Gas) 10000 9000 8000 `a E 7000 Si e c 60DO o_ e 5000 a 2 4000 S d '3 3000 a LL 2000 1000 0 Ja �Qo, nwtand �Qg, nwbxi �Qw, nw" — HCPVO PRE S 5000 x 4500 C a A A 4000 • a 0 0 3500 d 3000 W 2500 5 • POP has acted like a gas field from early in its development • 85% of reservoir volume produced is gas. • Objective of gas sales is to turn the dominant remaining phase into recovered hydrocarbons. • by n%wort Alaska LNG Project has advised gas supply to the GTP must be maintained, under normal operations, at rate of -3.5 BSCFD annual average untreated gas GTP feed rate of -3.5 BSCFD rate allows for 0.4 - 0.5 BSCFD for in -State demand and -2.7 BSCFD LNG facility inlet demand POP's total gas offtake would also include lease fuel and minor North Slope sales sales and Miscible Injectant NO used outside of the POP in Prudhoe Bay Unit satellites. 4.1 BSCFD allows PBU flexibility - to supply the full GTP feed rate in the event of supply disruptions from other fields, to accommodate improved Alaska LNG Project facility performance and to allow operational flexibility OfftakeGas POP Offtake - POP Offtake - MGS Reference MAG Sensitivity Case (Normal Case Operations) E:JI-IIVT .. 2.7 -3.6* * Higher supply rate due to higher CO2 concentrations in POP than in other fields • Gas OfFtake Produce gas from existing well stock Optimize offtake with: Targeted re -completion for gas Injector to producer conversions Two redundant offtake points at Central Gas Facility (CGF) Upgrade select equipment to ensure reliable gas delivery AKLNG Project participants are designing the GTP to return the CO2 byproduct to PBU Conceptual CO2 receipt and distribution system / miles 3 miles 2 miles WPZ WP W CO2 Control Module CGF 0 5 miles CO2 from GTP h 1 miles) APEX PL GC-2 GC-1 3 miles 2 miles 5 miles GC-3 CO2 Receipt and Injection EWE is the most promising option. Injection into Eileen West End (EWE) through new pipeline to existing wells at well pads W and Z Additional CO2 injection options outside POP will be evaluated for additional enhanced recovery opportunity Backup capability could be FS2 and the Apex injectors a • POP MGS Reference Case Offtake Profilerd *l Redacted Confidential Information IM 0 • POP MAC Sensitivity Case Offtake P I", A-1 Redacted Confidential Information 11 • • Prediction Results — GTP Gas Supply E�ti • Results of MGS reference case demonstrate POP is capable of delivering planned plateau gas supply for approximately 20 years. • Total gas supply from POP over project period is comparable for MGS reference 0 and MAG sensitivity cases Redacted Confidential Information W Prediction Results -Average Reservoir '" •• Pressure POP pressure declines about 100 psi / year in the MGS reference case during the plateau period, but remains sufficient to sustain the planned gas supply. • POP pressure decline slightly greater in the MAG case, but still remains sufficient to sustain planned gas supply. Redacted Confidential Information E MGS, MAG and Oil Reference Case - POP Oil and NGL Offtake Cumulative curves include - :.OE �' totals Redacted Confidential Information 14 • • Key Prediction Results -BOE Production • Redacted Confidential Information The net total BOE recovery increase from POP due to MGS is —3.6 Billion BOE. • Cumulative oil during major gas sales is decreased by <300 million bbls, due to pressure impacts, but greatly offset by increased BOE's from gas sales. Key Prediction Results Recovery The MGS reference and MAG sensitivity cases demonstrate the substantial increased hydrocarbon recovery from POP due to MGS compared to the Oil Reference case • 20.0 ■ Gas Sales 18.0 ■ Remaining Oil+NGL 16.0 Produced Oil+NGL to 1/1/2015 W m 14.0 c 0 12.0 a v 10.0 0 u 'al 8.0 a m 6.0 o. 4.0 2.0 Reference Oil Case MGS Reference Case MAG Sensitivity Case —3.5-3.6 billion BOE's additional HC recovery from POP due to MGS. IL The current field activity prepares for MGS: Active drilling program Rig workovers to maintain healthy well stock Continued Gas Cap Water Injection (GCWI) Active non -rig well work programs Waterflood and MI management BPXA and the other unit owners will continue to actively manage field optimization of the depletion strategy to enhance field performance into the future 0 I� Redacted Confidential Information 4 by The Alaska LNG schedule basis is for a 2025 start-up. It is unknown when or if other major gas sales opportunities will come Later initiation of gas sales by more than 5 years will decrease recovery, as fuel gas impacts become larger than oil impacts Later gas sales increases risk of facility life impacts on recovery (not accounted for in profiles). 0 PBU FFM used to test sensitivity to injection of PTU gas into POP starting in 2023 at rate of —800 MMSCFD. Inject 0.6 TCF of PTU gas into POP. In 2025 PTU and POP deliver gas to GTP Results: Negligible net impacts to oil recovery POP oil rates decrease during PTU gas injection Additional pressure provides some compensating oil benefits Redacted Confidential Information by t 2 Summary Conclusions .• The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) - A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic • feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access of the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved 20 Objective Requesting modification to AlO 3A and 4F for the POP m_ Explain technical benefits and implications of injection CO2 into POP • V Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economicall beneficial for enhanced recovery and pressure maintenance y Total GTP supply in the MGS reference case assumes 25% delivered from non -POP sources. Currently POP produces and injects —800 MMSCFD of CO2 as part of field operations The AlO modification requests approval to inject GTP CO2 By - Product (POP CO2 plus an estimated ~40 MMSCFD from PTU). Estimated GTP CO2 By -Product: • POP — 3.1 TCF • PTU — 0.3 TCF • Total — 3.4 TCF Redacted Confidential Information 22 0 by CO2 handling limitations Corrosion mitigation limits CO2 concentrations in equipment Increased CO2 concentration impacts equipment operational efficiency (turbines, flares, de -hydration) Gas liquefaction must have very low concentrations CO2 for LNG processing. -- GTP CO2 processing capacity is expected to limit overall inlet gas CO2 concentrations. F Current modeling assumptions - Wells shut-in upon reaching 25 mole% CO2 - The GTP will have a CO2 handling limit 0 CO2 Injection Locations Investigate The PBU FFM was used to determine the most promising location in the POP for GTP CO2 by-product injection for total hydrocarbon recovery Injection areas investigated: Eileen West End (EWE) Flow Station 2 Area (FS-2) Gas Cap — behind GCWI Injectors 24 • 0 EWE is the most promising location for CO2 injection for total hydrocarbon recovery - EWE CO2 injection limits migration to high gas recovery areas 2 E Fee Data Vlex Point Gnd SpecWm Display Web Help EWE - 2055 a---T a— _ G p A FIT. Daa AmPolllt Grid Speet m Display Wells Help �'- --- 99i t1K W. 100% CO2 Ns a* j — y m*h FFMIdt1`°'° 2025 °°'.n FOe Data 'AMPOW Gnd Speetme, Dspay Well Help .1231 Fee Dtla Vi-Pass! Geld Speenum Display Wells Help �..,... Tlme: O1JlJ12055 "".."...�.i x i^� LM I W% COY In FS2 FS-2 - 2055 `°m""`"` Gas Cap - 2055 Blue indicates higher CO2 concentrations by 4�"o I Is Ti., 01 JAN?OM AK LNG IIW% C011n GasCay CO2YM I F Hon .�...__._._... Grid 0 dly090_ i 26 PBU FFM used to test sensitivity of reservoir to additional 0.3 TCF CO2 removed from PTU gas Same total BOE recovery as MGS reference case within model resolution qW Injection of CO2 removed from PTU gas into POP creates no discernable change to ultimate hydrocarbon recovery from POP Redacted Confidential Information 27 0 • Additional Topic of Interest Alternate CO2 Usage in PBU - Studies MI, CO2 Injection Lab Studies •.. r. Point McIntyre 0 _ Borealis Orion 9 Tools developed for CO2 injection benefit prediction -- EOS models tuned to CO2 lab data Type patterns Type pattern scale -up tools (COBRA) _. Compositional full field models ir Continuing to perform development studies to evaluate potential use of • CO2 within PBU 28 y w i a M ' t r u a. . . . . . . . . . Redacted Confidential Information To achieve upside all CO2 handling limitations need to be removed. High side assumes MI injection discontinued in 2015 with no additional FOR recovery. ON • bp Summary --- CO2 handling limitations impact CO2 injection development options - POP is injectinga similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will continue to evaluate potential locations where CO2 injection may be economically beneficial for enhanced recovery and pressure maintenance 30 • All opinions, assessments and analyses (including forward looking or predictions of future activities) in this presentation are those of BP Exploration (Alaska) Inc., in its capacity as an individual working interest owner in the Prudhoe Bay Unit. The PBU FFM consists of three parts: (i) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (i) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as cases or scenarios) are generated by inputting the FFM Inputs into the FFM Tool. FFM runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive the details of PBU operational or technical data (e.g., specific geological data) from FFM runs. BPXA uses the FFM Tool to generate FFM runs for both itself and, upon request, for the PBU working interest owners. All references in this testimony to the FFM (or to PBU FFM) are a reference to FFM Inputs plus the FFM Tool. 31 Portions held confidential in secure storage Colo mbie, Jody J (DOA) From: Schultz, Jon S <Jon.Schultz@conocophillips.com> Sent: Friday, September 04, 2015 2:28 PM To: Roby, David S (DOA) Cc: gilbert.wong@exxonmobil.com; Luna, Charles S (charles.s.luna@exxonmobil.com); pmayer@chevron.com; abible@chevron.com; john.dittrich@bp.com; glyle@guessrudd.com; chris.wyatt@bp.com; Reinbold, Eric W; Evans, John R (LDZX); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Colombie, Jody J (DOA); Wallace, Chris D (DOA) Subject: RE: Supplemental information on CO2 disposal (dockets: NO 15-032, NO 15-033, and CO 15-09) Mr. Roby, Thank you very much for your note and opportunity to clarify our disposal request. The 2015 EPA Guidance supports CO2 disposal in Class II wells except where "the primarypurpose [is] long-term storage ... [and] there is an increased risk to USDWs ... ", and only where Class 11 regulatory tools cannot manage the increased USDW risk (2015 EPA Guidance, at 2 and note 1, emphasis in original) (quoting 40 CFR 144.19). Accordingly, the Commission's authority to authorize Class II CO2 disposal, as supported by the 2015 EPA Guidance, is broad. That said, CPAI's request for the Commission to authorize disposal is narrow and tailored to the circumstances you describe in your note below. Specifically, CPAI requests that the Commission authorize CO2 disposal in Class II wells only where, as you state, an "enhanced recovery project is no longer viable." If an enhanced recovery project is viable, the CO2 would be injected and used for enhanced recovery. As we stated in our Comments and testimony, the working interest owners have done considerable work examining potential enhanced recovery opportunities; we will continue this work in advance of projected AKLNG start-up in 2025, We hope this clarification assists the Commission's consideration of our request. Please advise if CPAI can provide any further information or clarification. Responsive to your last question, CPAI does not request at this time that the Commission leave the record open beyond Sept. 8. Thank you very much. Regards, Jon Schultz ConocoPhillips Alaska Manager, Greater Prudhoe Area Office: +1-907-265-1315 Mobile: +1-907-227-8708 From: Roby, David S (DOA) [mailto:dave.roby@alaska.ciov] Sent: Friday, September 04, 2015 12:07 PM r.c: ggibert.wong0exxonmobil.com; Luna, Charles S(charles.s.luna@exxonmobil.com); pmayer0chevron.com; abible0chevron.com; iohn.dittrich0bp.com; glyle0guessrudd.com; chris.MattObp.com; Reinbold, Eric W; Evans, John R (LDZX); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Colombie, Jody J (DOA); Wallace, Chris D (DOA) Subject: [EXTERNAL]Supplemental information on CO2 disposal (dockets: AIO 15-032, AIO 15-033, and CO 15-09) Mr. Schultz, Thank you for your letter dated September 3, 2015, in response to the AOGCC's request at the August 27, 2015, hearing on gas offtake from PBU that ConocoPhillips explain how the AOGCC has authority to approve CO2 disposal in Class II wells as opposed to requiring that CO2 disposal be conducted in Class VI CO2 sequestration wells. We are, frankly, reading and interpreting the April 23, 2015, EPA memo quite differently than you are. The memo clearly states that CO2 injection for enhanced recovery purposes is a Class If operation, which the AOGCC concurs with, however what you're proposing is CO2 disposal and by our reading of the EPA memo that can only be done as a Class II operation if it is using Class II wells that were formerly used for enhanced recovery operations but the enhanced recovery project is no longer viable. Injection of CO2 into a disposal interval or into a deep portion of the Ivishak aquifer where injection would not contribute to enhanced oil recovery would not fall into the narrow definition of when the EPA says that Class II wells can be used instead of Class VI wells for CO2 disposal. Unless you have something directly from the EPA that clearly shows that our interpretation of their memo is incorrect I'm afraid I will have to recommend that the Commissioners reject your application for authorization of CO2 disposal at this time. If you have such a document please submit it, if you do not but would like to ask the EPA to weigh in on this matter on the record we'd be willing to keep the record open for a reasonable amount of time to allow them to do so. Please advise before COB Tuesday September 8th if you'd like us to keep the record open and if so for how long. Regards, Dave Roby Sr. Reservoir Engineer Alaska Oil and Gas Conservation Commission (907)793-1232 • ConocoPhillips Alaska September 3, 2015 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 RECEIVED SEP 03 2015 ,AOGCC Jon Schultz Manager Greater Prudhoe Area P.O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1315 RE: Docket Numbers: AIO 15-032, AIO 15-033, CO 15-09 — Prudhoe Bay Unit ConocoPhillips Alaska, Inc. (CPAI) Supplemental Submission Re AOGCC Authority to Authorize Disposal of Gas Treatment Byproducts, Principally Comprising Carbon Dioxide, In Class II Wells Dear Commissioner Foerster, At the August 27, 2015 hearing in the above referenced matter, the Alaska Oil and Gas Conservation Commission (Commission) requested that CPAI provide supplemental information regarding the Commission's authority to approve disposal of gas treatment byproducts, principally comprising carbon dioxide (CO2), in Class II PBU wells (Supplemental Submission). More specifically, at the August 27 hearing, the Commission received into the record an April 23, 2015 guidance letter from the United States Environmental Protection Agency (EPA) Director of the Office of Ground Water and Drinking Water, referencing key principles related to transition of Class II to Class VI wells (2015 EPA Guidance, attached). The Commission requested that CPAI explain how the 2015 EPA Guidance supports the Commission's authority to authorize CO2 disposal in Class II wells. 1. Background: Underground Infection Control Program Under the Safe Drinking Water Act, EPA is authorized through the Underground Injection Control (UIC) program to regulate the injection of fluids into underground wells in order to ensure underground sources of drinking water (USDWs) are not impaired. EPA's UIC regulations govern the siting, construction, operation and closure of six "classes" of underground injection wells - referred to as Class I through Class VI -which vary according to the potential for the class of injected fluid to impact USDWs. See 40 C.F.R. § 144.6. The two UIC well classes pertinent to the Commission's inquiry in this matter are: • Class II - Class II wells are primarily used by the oil and gas industry to inject fluids either for enhanced recovery (ER) or exploration and production waste disposal. • • CPAI Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class II Wells Page 2 of 4 September 3, 2015 • Class VI - In late 2010, EPA promulgated regulations establishing a new category of injection wells defined to be wells "used for geologic sequestration of carbon dioxide beneath the lowermost formation containing a USDW[.]" 40 C.F.R. § 144.6(f).' A state or tribe may apply for and obtain from EPA primacy (lead administration and enforcement authority) for one or all of the six classes of UIC wells. The State of Alaska, through the Commission, has obtained primacy to administer and enforce the Class II UIC program in Alaska. The State of Alaska has not yet sought primacy to administer and enforce the Class VI UIC program.2 Though it has existed for five years, the Class VI program is not widely used. At this time, EPA has approved Class VI wells for two applicants, and estimates that 6 to 10 additional commercial Class VI wells will come online by 2016.3 By comparison, EPA reports that there are approximately 172,068 Class II wells currently in operation.4 2. The 2015 EPA Guidance Clarifies That the Commission Has Authority to Approve CO2 Disposal or Storage In Class II Wells In its 2015 guidance letter, consistent with well -established Class II regulation of both enhanced recovery injection and exploration and production waste disposal, EPA pragmatically encourages use of Class II wells for CO2 injection for ER, as well as for CO2 disposal or storage.5 EPA recognizes that "CO2 storage associated with Class II wells is a common occurrence ...." 2015 EPA Guidance at 1. EPA notes that "CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery". Id. This is consistent with current PBU enhanced recovery operations. As BPXA notes in its pre -filed testimony, CO2 is a significant component (comprising approximately 800 mmscf/d) of the gas currently reinjected in the Prudhoe Oil Pool (POP) for enhanced oil recovery. (BPXA Pre -Filed Testimony, at 12.) As the Commission is aware, in the major gas sale development phase of Prudhoe Bay, after commencement of natural gas offtake, treatment and export, natural gas reinjection into the POP to support enhanced liquid recovery would decrease over time. Also in this next phase, gas treatment byproduct, principally comprising CO2, would be injected. Although this CO2 would be preferentially used for ER, if viable ER opportunities are not identified, the CO2 would be injected for disposal (as, for example, produced water would be injected for disposal, where viable ER opportunities for water injection are not presents). Regarding such Class II CO2 injection in later phases of oil and gas development, EPA states: See generally40 C.F.R. § 146.81 et seq. (EPA's UIC Class VI program regulations). 2 The 2015 EPA Guidance encourages states to apply for primacy for all well classes, including Class VI 3 See http://www.epa.gov/r5water/uic/adm/ (reporting on the issuance of two Class VI UIC wells to Archer Daniels Midland, one of which had been appealed to the Environmental Appeals Board); http://www.epa.gov/r5water/uic/futuregen/ (addressing Class VI permits issued to FutureGen Alliance 2.0). 4 http://water.epa.gov/type/g_roundwater/uic/wells.cfm. 5 The 2015 EPA Guidance generally refers to CO2 "storage". In the context of Alaska's Class II program, "storage" of CO2 would constitute "disposal". See 20 AAC 25.252 and note 6 below. s Like produced water, if not used for ER, the gas treatment byproduct stream would be conventional oilfield waste. See 58 Fed. Reg. 15284, 15286 (Mar. 22, 1993); EPA Report to Congress on the Management of Waste from the Exploration, Development, and Production of Crude Oil, Natural Gas, and Geothermal • • CPAI Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class II Wells Page 3 of 4 September 3, 2015 If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a CO2 ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. 2015 EPA Guidance at 2 (emphasis in original). EPA further states: The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class II program. Transition to Class VI should only be considered if the Class l/ tools are insufficient to manage the increased risk. The key regulation, "Transitioning from Class II to Class VI," codified at 40 CFR 144.19, states that owners or operations that are injecting carbon dioxide for the primarypurpose of long-term storage into an oil and gas reservoir must apply and obtain a Class VI GS permit when there is an increased risk to USDWs compared to Class 11 operations. 2015 EPA Guidance at 2 and note 1 (first emphasis added; second and third emphases in original). This EPA guidance directly supports the Commission's authority to authorize CO2 disposal in Class II PBU wells. As BPXA states in its application, there is no underground freshwater source within the PBU; accordingly, there is no risk of movement of injected CO2 into USDWs. BPXA and EMAP Consolidated Application at 6. Applying this key fact to EPA's guidance, because there is no increased risk to USDWs, even if viable enhanced recovery opportunities are not identified, and CO2 and other gas treatment byproducts are injected into the reservoir for disposal or storage, rather than enhanced recovery, Class II tools will remain sufficient to manage any risks. Accordingly, there will be no reason or requirement to transition any PBU Class II operation to Class VI. As PBU CO2 disposal or storage will remain a Class II operation, the Commission has and will retain authority to approve and regulate it. We trust this Supplemental Submission addresses the Commission's request. If there is additional information that CPAI can provide, we would be pleased to do so. Sincerely, iLlltz, Manger, Greater Prudhoe Area Phillips AI ska, Inc. Energy, EPA530-SW-88-003, Vol. 1, at p. II-18 (Dec. 1987); EPA530-K-01-004, Exemption of Oil and Gas Exploration and Production Wastes from Federal Hazardous Waste Regulations at 7 (Oct. 2002). CPAI Supplemental Submission Re Commission Authority to Approve CO2 Disposal in Class II Wells Page 4 of 4 September 3, 2015 Attachment 1 — April 23, 2015 EPA Guidance cc via email: Gilbert Wong, EMAP (gilbert.wong(o)exxonmobil. com) Steve Luna, EMAP(charles.s.luna(cDexxonmobil.com) Phil Ayer, CUSA (pmayer(a)chevron.com) Angie Bible, CUSA (abibleCa-)_chevron.com) John Dittrich, BPXA (John. Dittrich(a)bp.com) George Lyle, Guess & Rudd (glyle(cD-guessrudd.com) Chris Wyatt, BPXA (Chris.Wyatt(D-bp.com) Eric Reinbold, CPAI (Eric.W.Reinbold(a--)conocophillips.com) John Evans, CPAI (John. R.Evans(a)conocophillips.com) Attachment 1 April 23, 2015 EPA Guidance See attached. arts t> Sr,�, I I. W x� o`er tilq� PRO,�'G� UNITED STATES ENVIRONMENTAL PROTECTION AGENCY WASHINGTON D C 20460 OFFICE C?F WATER MEMORANDUM FROM: Peter C. Grevatt. Director Office of Ground Water and Drinking Water TO: Regional Water Division Directors SUBJECT: Key Principles in EPA's Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil or Gas Recovery Wells to Class VI Most states have primary enforcement responsibility (i.e.. primacy) for the Class 11 Underground Injection Control program for oil or gas -related injection activities, while EPA Regions currently retain direct implementation authority for the Class VI program in every state. The shared implementation of the UIC program necessitates a clear articulation and common understanding of the potential for transition of enhanced recovery wells from Class II to Class VI, consistent with EPA's Class VI Rule. This memo is intended to emphasize the key principles in EPA's UIC Class VI Rule related to the transition from Class II to Class VI for ER wells that inject carbon dioxide for long-term storage. As Regions work with states on implementation of the Class VI program, I encourage you to assist states in submitting primacy applications for all well classes, including Class VI. EPA recognizes the importance of geologic sequestration of anthropogenic CO2 far climate change mitigation. The UIC Class VI Rule was developed to facilitate GS and ensure protection of underground sources of drinking water from the particular risks that large scale COz injection for purposes of long- term storage may pose. The following are key principles related to the transition of ER wells that store COz from Class II operations to the Class V1 program: 1. Geologic storage of COz can continue to be permitted under the UIC Class 11 program. ER wells across the U.S. are currently permitted as UIC Class II wells. CO2 storage associated with Class II wells is a common occurrence. and CO2 can be safely stored where injected through Class I1-permitted wells for the purpose of oil or gas -related recovery. 2. Use of anthropogenic CO2 in ER operations does not necessitate a Class V1 permit. ER operations can continue to be permitted as Class 11 wells, regardless of the source of CO2. An owner or operator of an ER operation can switch from using a natural source to an anthropogenic source of CO> without triggering the need for a Class VI permit. enterr!et Address WRY r • http irwwx epa gcv RecyctedrRecyclable • P- nteis ir•ytrtahre 0,1 Basta Inks on iC1p^: Postcnnsu n<r Process Cntcnre Free Recycled Pape, 3. Class VI site closure requirements are not required for Class II CO2 injection operations. A Class II well that has been used for injection ofanthropogenic or non-anthropogenic CO2 and has been operated within its permit conditions can be closed as a Class II well. 4. f ER operations that are focused on oil or gas production will be managed under the Class II program. If oil or gas recovery is no longer a significant aspect of a Class II permitted ER operation, the key factor in determining the potential need to transition a COz ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class ]I program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of COz. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class 11 program. Transition to Class VI should only be considered if the Class II tools are insufficient to manage the increased risk. S. The Class If and Class VI directors should work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director (in most cases a state official) will have the relevant data on pressure and volume of COa injected into Class I1 ER operations, which will influence any transition decision. EPA encourages the Class 11 director to contact the Class VI director where he/she believes the risk has changed as a result of significant storage of COi in the reservoir. 6. , The best implementation approach is for states to administer both the Class II and the Class VI UIC programs. EPA encourages states to apply for primacy for all well classes, including Class VI. Based on our conversations with states. in most cases, states who are approved for primacy for the Class VI program are expected to administer the program through their oil and gas program. The Office of Ground Water and Drinking Water is currently working with the U.S. Department of Energy, state associations, EPA Regions and stakeholders to finalize technical guidance focused on risk factors discussed in the Class VI Rule at 40 CFR 144.19. As we complete the final guidance, we wil I work to ensure that these key principles remain clear. Please contact me or have your staff contact Ron Bergman at 202-564-3823 if we can be of assistance to you on these or other U I C program issues. r The key regulation, "Transitioning from Class 11 to Class VI," codified at 40 CFR 144.19, states that owners or operators that are injecting carbon dioxide for the primary purpose of long --term storage into an oil and gas reservoir must apply for and obtain a Class V I GS permit when there is an increaser! risk to USDWs compared to Class If operations. IV 0 • NAME STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Public Hearing Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit August 27, 2015 at 9am AFFILIATION Testify (yes or no) /"ter �a///5 /r" / 0 �C� %!� n At �Li c A/ E RAG., 5 ty'? Q P 1,1 c & "* S r 0 ,P�,h �J c�� '� O 40*,,e� P-A i r -l4qA .bVgl BOG -Aask 6,"-k- .d 1" &4 /l/o tit�r W-1-t k.. �iA-rE: itra Le E • 1, 11.E i r • mac . AWAMM/' • aiAl"Vu- ep -N C) I�arvr, ��ver NeUq, IV • • /i ice... M — i _� r J i 0 UNITED STATES ENVIRONMENTAL PROTECTION AGENCY INASHINGTON D C 20460 (TFA E Of WAIER MEMORANDUM FROM: Peter C. Grevatt. Director Office of Ground Water and Drinking Water TO: Regional Water Division Directors SUBJECT: Key Principles in EPA's Underground Injection Control Program Class VI Rule Related to Transition of Class II Enhanced Oil or Gas Recovery Wells to Class VI Most states have primary enforcement responsibility (i.e., primacy) for the Class 11 Underground Injection Control program for oil or gas -related injection activities. while EPA Regions currently retain direct implementation authority for the Class V1 program in every state. The shared implementation of the UIC program necessitates a clear articulation and common understanding of the potential for transition of enhanced recovery wells from Class 11 to Class V1, consistent with EPA's Class VI Rule. This memo is intended to emphasize the key principles in EPA's UiC Class VI Rule related to the transition from Class 11 to Class V1 for ER wells that inject carbon dioxide for long-term storage. As Regions work with states on implementation of the Class VI program. I encourage you to assist states in submitting primacy applications for all well classes, including Class V1. EPA recognizes the importance of geologic sequestration of anthropogenic CO2 for climate change mitigation. The UIC Class VI Rule was developed to facilitate GS and ensure protection of underground sources of drinking water from the particular risks that large scale CO2 injection for purposes of long- term storage may pose. The following are key principles related to the transition of ER wells that store CO2 from Class 11 operations to the Class Vl program: 1. Geologic storage of CO2 can continue to be permitted under the UIC Class 11 program. ER ,.yells across the U.S. are currently permitted as UIC Class I1 wells. CO2 storage associated with Class II wells is a common occurrence. and CO2 can be safely stored where injected through Class II -permitted wells for the purpose of oil or gas -related recovery. 2. Use of anthropogenic CO2 in ER operations does not necessitate a Class VI permit. ER operations can continue to be permitted as Class 11 wells, regardless of the source of CO2. An owner or operator of an ER operation can switch from using a natural source to an anthropogenic source of CO2 without triggering the need for a Class V1 permit. irternet Address +URL i • http t:.•rx:t eFa gar RecyctediRecyctabte • Pr ,, =t ,s,th Veyetabte M Rased mils on T10 PostconsLjme_r Pircess Chr-7?rme Free RecycieA paper • s 3. Class VI site closure requirements are not required for Class II CO2 injection operations. A Class II well that has been used for injection of anthropogenic or non-anthropogenic CO2 and has been operated within its permit conditions can be closed as a Class I I well. 4. f ER operations that are focused on oil or gas production will be managed under the Class 11 program. If oil or gas recovery is no longer a significant aspect of a Class 11 permitted ER operation, the key factor in determining the potential need to transition a CO2 ER operation from Class II to Class VI is the increased risk to USDWs related to significant storage of CO2 in the reservoir, where the regulatory tools of the Class II program cannot successfully manage the risk. The most direct indicator of increased risk to USDWs is increased pressure in the injection zone related to the significant storage of CO2. Increases in pressure with the potential to impact USDWs should first be addressed using tools within the Class 11 program. Transition to Class VI should only be considered if the Class II tools are insufllcient to manage the increased risk. 5. The Class II and Class VI directors should work together to address the potential need for transition of any individual operation from a Class II to a Class VI permit. The Class II program director (in most cases a state official) will have the relevant data on pressure and volume of CO2 injected into Class II ER operations, which will influence any transition decision. EPA encourages the Class II director to contact the Class VI director where he/she believes the risk has changed as a result of significant storage of CO2 in the reservoir. 6. - The best implementation approach is for states to administer both the Class If and the Class VI UIC programs. EPA encourages states to apply for primacy for all well classes, including Class V1. Based on our conversations with states, in most cases, states who are approved for primacy for the Class V1 program are expected to administer the program through their oil and gas program. The Office of Ground Water and Drinking Water is currently working with the U.S. Department of Energy, state associations, EPA Regions and stakeholders to finalize technical guidance focused oil risk factors discussed in the Class VI Rule at 40 CFR 144.19. As we complete the Final guidance, we will work to ensure that these key principles remain clear. Please contact me or have your staff contact Ron Bergman at 202-564-3823 if we can be of assistance to you on these or other U I C program issues. ' The key regulation, "Transitioning from Class 11 to Class Vl," codified at 40 CFR 144.19, states that owners or operators that are injecting carbon dioxide for the primary purpose ojlong-terin storage into an oil and gas reservoir must apply for and obtain a Class V l GS permit when there is air increased risk to USDJYs compared to Class ll operations. Tom Lakosh 3301 Eureka Street, A 12 Anchorage, Alaska 99503 phone/fax (907) 563-7380 email: lakosh@gci.net August 27, 2015 Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission RECEIVED AUG 27 2015, AOGCC 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Sent via email to: Jody.Colombie@alaska.gov and samantha.carlisle@alaska.gov Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule The BP/Exxon application under consideration at today's public hearing should be rejected because the BPU operator must make the application as representative of all lessees who must agree on a future plan production that must be approved by DNR. ConocoPhillips clearly objects to the requested gas off -take volume and the unit lessees must first submit the proposed gas production plan through the unit operator to DNR under unit consensus rules and not as separate competing interests to AGOCC. The proposed gas off -take amounts should similarly be rejected as they do not fairly consider new proposed uses of POP gas such as a local LNG plant in the planning stages and power production for the pipeline's Gas Treatment Plant or the pipeline compressors. The applicants should be required to document these other proposed uses in consideration of their higher value added and increased pressure drops on oil production fields. The application should be rejected as it fails to provide the public sufficient information to insure their rights to maximum production of hydrocarbons on the unit. The information must minimally show that there is sufficient reinjection of CO2 to maintain POP pressures for continuing oil production at maximum rates. Where the CO2 available from the GTP falls far short of the gas removed from POP, the commission should require CO2 capture and injection from all power production available in the area. The commission should also recommend applicants investigate advanced carbon capture and power production technology such as supercritical CO2 turbines and/or post combustion CO2 capture to insure that the lowest cost for FOR and pool pressure maintenance can be achieved. The CO2 available from S-0O2 turbines may be more effective for FOR given the higher pressures and temperatures that may be available from the turbine exhaust/heat recuperation system. 0 0 Where miscible injectants such as natural gas liquids used in conjunction with hot CO2 have been shown to substantially enhance oil recovery, including recovery of under - produced heavy oils, the AGOCC should not approve this application unless and until the commission and the public can revisit the efficacy of CO2 injection with the newly available NGLs from Point Thomson. Where applicants have previously failed to disclose or employ injection of available CO2 from all sources to provide for maximum hydrocarbon production from state leases, the AGOCC must retroactively evaluate the value of lost production and assess fines to recuperate lessor's losses to date in addition to mandating maximum FOR using CO2 and miscible injectants in the future. The requested maximization of CO2 capture and injection will not only improve production on state leases in the near term, but can set industry standards that could substantially reduce the carbon footprint of the gas and power production industries as a whole. These practices may help minimize or reverse climate change in Alaska to allow for longer drilling seasons and still greater annual oil production as is the mandate for the AOGCC. The AGOCC must definitively determine whether CO2 capture and injection is a viable substitute for natural gas reinjection as it is clear that the natural gas off -take now has a viable market to produce value for the owner citizens of Alaska and new technologies for carbon capture from raw well gas and power production may drive the economics of gas off -take where CO2 injection can be used to maintain pool pressures and enhance oil migration to production wells. The AGOCC must remain vigilant in its assessment of FOR opportunities going forward and demand that lessees adopt new CO2 capture and injection technologies as they become commercially available as they may present a viable alternative for maintaining maximum hydrocarbon liquids and gas production consistent with lease provisions. The public hearing process should be continued until the application can be amended to clearly show the public owners of the hydrocarbon resources that the maximum production of all leased hydrocarbon reserves will be maintained. The applicants' confidential submissions must be minimally redacted to preserve trade secrets while allowing a fair public review of the possible gas and oil production alternatives consistent with their constitutional rights and lessees obligations to extract hydrocarbon resources at their maximum sustainable rate. We should not be forced to leave oil in the ground to produce gas for sale where CO2 can be economically captured from any, or all local sources and injected to maintain pool pressures and enhance oil recovery. Sincerely, Tom Lakosh ExxonMobil Production Company P. O. Box 196601 Anchorage, Alaska 99519-6601 907-561-5331 Telephone 906-564-3677 Facsimile August 27, 2015 Ms. Cathy P. Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Cory Sarles Alaska Production Manager E-zFonMobil Production AUG 2 7 2015 Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: On July 17, 2015, BP Exploration (Alaska) Inc. (BPXA) filed with the Commission a Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Order AIO 3A and AIO 4F (the Application) which was filed on behalf of ExxonMobil Alaska Production Inc. (ExxonMobil) as an individual working interest owner in the Prudhoe Bay Unit. ExxonMobil supports the request to increase the maximum annual average gas offtake rate for the Prudhoe Oil Pool from the current 2.7 billion standard cubic feet per day to 4.1 billion standard cubic feet per day. ExxonMobil also supports the request to modify Area Injection Orders AIO 3A and AIO 4F to authorize injection of a byproduct stream from the Alaska LNG Project Gas Treatment Plant, composed of CO2, and other effluent gases from sources within or outside the Prudhoe Bay Unit. The application seeks approvals from the Commission that will support work by the parties in the Alaska LNG Project, and allow progress to the next, front-end engineering and design, stage for that project. A maximum annual average gas offtake rate of 4.1 billion standard cubic feet per day, and modification of the Area Injection Orders to allow injection of CO2 is in accordance with good oil field engineering practice. The requested actions are appropriate for the Commission to take. ExxonMobil also supports the pre -filed testimony, witness presentations, and other supporting evidence presented by BPXA to the Commission in support of the Application. ExxonMobil respectfully asks that the Commission approve the request set forth in the application by BPXA. Sincerely, CEQ:J c xc: Commissioner Daniel T. Seamount Dave P. Lachance, BPXA A Division of Exxon Mobil Corporation Prudhoe Oil Pool Major Gas Sales Presentation to the AOGCC by BPXA as an individual Prudhoe Bay Unit working interest owner General overview of the Alaska LNG project Support Rule 9 Application for amendment of CO 341 D Rule 9 for the Prudhoe Oil . Pool (POP) Technical justification for increasing the maximum allowable gas offtake from 2.7 to 4.1 BCFD Address several topics of interest for the AOGCC Support Application for AlO Modification of AlO 3A and AlO 4F Technical justification for request to inject CO2-byproduct into the POP for Enhanced Recovery and Pressure Maintenance An integrated liquefied natural gas export project Alaska that would provide access to gas for Alaskans GasTreatment Plant (GTP) • 3.3 BSCFD peak export rate • Three trains • CO2 removed for injection at PBU Liquefaction Facility • Natural gas is cooled to -260 deg F • 3 trains dehydrate, and liquefy gas to produce up to 20 million tons of LNG each year LNG Storage & Marine Terminal • LNG storage tanks • Two jetties for LNG carriers Beaufort Sea PRUDNOE BAY Point -------------- ',Thomson , - - - - - DELTA kUNCT10N ! Tok VALDEZ j ,Subject to Change �1 0° Gulf of Alaska V Source: AK LNG Point Thomson Transmission Line (PTTL) • —60 miles, 32" diameter above ground Prudhoe Bay Transmission Line (PBTL) • —1 mile, 60" diameter above ground Gas Pipeline • 800+ mile 42" diameter below ground gas pipelin! • 6-10 compressor stations • Up to 5 in -state off -take points Artists renditions of LNG and GTP GRSLINE 0 ConocoPhillips E inMobil C(� TransCanada ONHOPyERi (OR P 3 The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners to access the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved • 0 olume Basis Alaska LNG Project has advised gas supply to the GTP must be maintained during normal operations at a rate of —3.5 BSCFD annual average untreated gas GTP feed rate of —3.5 BSCFD rate allows for 0.4 - 0.5 BSCFD for in -State gas demand and —2.7 BSCFD to satisfy LNG facility inlet demand • POP's total gas offtake would also include lease fuel, minor North Slope sales and Miscible Injectant (MI) used outside of the POP in Prudhoe Bay Unit satellites. 4.1 BSCFD allows POP flexibility - to supply the full GTP feed rate in the event of supply disruptions from other fields to accommodate improved facility performance and allow operational flexibility OfftakeGas POP Offtake - POP Offtake - MGS Reference MAG Sensitivity Case (Normal Case Operations) • • ~23 -3.6* * Higher supply rate due to higher CO2 concentrations in POP than in other fields • Gas OfFtake Produce gas from existing well stock Optimize offtake with: Targeted re -completion for gas Injector to producer conversions Two redundant offtake points at Central Gas Facility (CGF) Upgrade select equipment to ensure reliable gas delivery AKLNG Project participants are designing the GTP to return the CO2 byproduct to PBU Conceptual CO2 receipt and distribution system 7 miles 3 miles Fmiles WPZ WP W CO2 Control Module CGF 0.5 miles CO2 from GTP APEX PL (— 1 miles) --- GC-2 GC-1 ...r 3 miles 2 mdes 5 miles GC -3 VALVF. MODULE FFM a €e« MALES OAS METE t, ODULE 32' W .,�. �• S WSSQ CO2 Receipt and Injection Injection into Eileen West End (EWE) through new pipeline to existing wells at well pads W and Z EWE is the most promising option. Additional CO2 injection options outside POP will be evaluated for additional enhanced recovery opportunity Backup capability could be FS2 and the Apex injectors • The current field activity prepares for MGS: Active drilling program Rig workovers to maintain healthy well stock • Continued Gas Cap Water Injection (GCWI) Active non -rig well work programs Waterflood and MI management BPXA and the other unit owners will continue to actively manage field optimization of the depletion strategy to enhance field performance into the future Summary Conclusions The Major Gas Sales (MGS) Reference Case (3.3 BSCFD) and the Maximum Allowable Gas (MAG) Sensitivity Case (4.1 BSCFD) both demonstrate significant additional hydrocarbon recovery from POP as a result of major gas sales Results of the MGS reference case demonstrate that POP is capable of delivering: Approximately 22 Trillion Standard Cubic Feet (TSCF) of hydrocarbon sales gas or 3.8 billion Barrels of Oil Equivalent (BOE) A gas sales plateau length of 20+ years Continued oil development and production The MAG sensitivity case produces an equivalent ultimate hydrocarbon recovery of between 17.7 and 17.8 billion BOE's An increase in Rule 9 gas offtake to an annual average of 4.1 billion standard cubic • feet per day (BSCFD) is consistent with good oil field engineering practices; and positions the Prudhoe Bay Unit working interest owners access the MGS opportunity afforded by the Alaska LNG Project, and therefore should be approved Objective Requesting modification to AlO 3A and 4F for the POP Explain technical benefits and implications of injection CO2 into POP Summary CO2 handling limitations impact CO2 injection development options POP is injecting a similar amount of CO2 under current field operations EWE is the most promising location for CO2 injection within the POP Additional CO2 from outside sources generates negligible changes to POP reservoir outcomes BPXA has studied and anticipates that the PBU working interest owners will i continue to evaluate potential locations where CO2 injection may be economically beneficial for enhanced recovery and pressure maintenance Summary of the Confidential Portion of BPXA's Testimony A A, Discussion of the Full Field Model and the quality and uses Forward prediction of the Oil Reference Case Detailed discussion of comparative cases and assumptions Description of gas delivery and CO2 handling MGS Reference Case profile MAG Sensitivity Case profile Expected recovery comparison MGS start date sensitivity AlO modification 2 studies already y conducted POP and non -POP CO2 recovery estimates All opinions, assessments and analyses (including forward looking or predictions of future activities) in this presentation are those of BP Exploration (Alaska) Inc., in its capacity as an individual working interest owner in the Prudhoe Bay Unit. The PBU FFM consists of three parts: (1) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (i) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as cases or scenarios) are generated by inputting the FFM Inputs into the FFM Tool. FFM runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive i the details of PBU operational or technical data (e.g., specific geological data) from FFM runs. BPXA uses the FFM Tool to generate FFM runs for both itself and, upon request, for the PBU working interest owners. All references in this testimony to the FFM (or to PBU FFM) are a reference to FFM Inputs plus the FFM Tool. Portion of presentation held confidential in secure storage • • STATE OF ALASKA Alaska Oil and Gas Conservation Commission Docket Numbers: AIO 15-032, AIO 15-033 and CO 15-09 Application for Amendment of Pool Rule 9 i � f RECEED Modification of AIOs 1 K Prudhoe Oil Pool, Prudhoe Bay Field AUG 2 5 2015 Written Submittal of BP Exploration (Alaska), Inc. AOGCC Submitted August 25, 2015 Commissioners: This submission and the accompanying appendices are a component of the application by BP (Exploration) Alaska, Inc. (`BPXA") as an individual working interest owner ("WIO") in the Prudhoe Bay Unit ("PBU") and not as PBU operator, on behalf of itself and PBU WIO ExxonMobil Alaska Production Inc. ("EMAP"), to the Alaska Oil and Gas Conservation Commission ("AOGCC" or "Commission"), for an amendment of Prudhoe Oil Pool ("POP") Rule 9 of Conservation Order ("CO") 341D and modification of PBU Area Injection Orders ("AIOs") 3A and 4F. INTRODUCTION The application requests that the Commission amend the maximum annual average gas offtake rate for the POP in CO 341 D Rule 9, from 2.7 billion standard cubic feet per day ("bscf/d") to 4.1 bscf/d. As demonstrated in the application and this testimony, a maximum annual average gas offtake rate of 4.1 bscf/d is in accordance with good oil field engineering practices and should be approved by the Commission. The application also requests that the Commission modify AIOs 3A and 4F to authorize the injection of CO2 for enhanced hydrocarbon recovery and reservoir pressure maintenance, from sources both within and outside the PBU. As demonstrated in the application and this testimony, the requested modification of AIOs 3A and 4F is in accordance with good oil field engineering practices and should be approved by the Commission. BPXA and EMAP are filing this application with the Commission so each PBU WIO has the ability to access the opportunity presented by the Alaska LNG Project (the "AK LNG Project") to progress major gas sales of Prudhoe Bay Unit natural gas ("PBMGS"). As the Commission knows, affiliates of the three largest PBU WIOs — BPXA, EMAP and ConocoPhillips Alaska, Inc. ("CPAI") are all working with the State of Alaska to develop the AK LNG Project. BPXA will provide a witness at the public hearing to testify further on the AK LNG Project from BPXA's perspective. 1 Written Submittal of Joloration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AlOs 3A and 4F This application and the requested approvals are necessary at this time for several reasons: (i) The requested approvals are needed so BPXA, EMAP and the other PBU WIOs have the ability to access the opportunity presented by the AK LNG Project for progressing PBMGS. The AK LNG Project participants have informed the PBU WIOs that the approvals requested in this application are necessary at this time to support progression of the project beyond pre -FEED engineering stage of development. The requested approvals are just one of many regulatory and facility planning activities on which the PBU WIOs have been diligently working to prepare for PBMGS. (ii) The requested approvals support individual PBU WIO and State of Alaska internal preparations for major gas sales, including preparations for marketing each party's respective share of PBU gas. BPXA and EMAP collectively own 63 percent of the working interests in the oil and gas leases that comprise the PBU. The ability of each PBU WIO and the State of Alaska (assuming an election by the State to take gas royalty in kind) to market its gas is fundamental to the success of the PBMGS opportunity presented by the AK LNG Project. LNG buyers will demand certainty of gas supplies to the AK LNG Project system, and without the certainty provided by the requested approvals, BPXA and EMAP respective LNG marketing efforts to monetize their shares of PBU gas production would be impeded. The inability of each company to progress its individual gas marketing efforts would hinder progress of the AK LNG Project. BPXA is submitting this sworn testimony in the form of this written narrative and associated exhibits. This testimony is provided by BPXA as an individual PBU WIO. BPXA has consulted and coordinated with PBU WIO EMAP in the preparation of this testimony, and has their support in the application. The assessments contained in this testimony have been discussed with the other PBU WIOs, CPAI and Chevron U.S.A. Inc. ("CUSA"). Section I of this submission identifies the witness who is submitting this written testimony on behalf of BPXA. Section II provides a brief summary of this testimony. Section III contains the substance of the testimony in support of an amendment to CO 341D Rule 9. Section IV contains the substance of testimony in support of modification of AIOs 3A and 4F. Section V, which is being separately submitted to the Commission as a Confidential Appendix to preserve confidentiality, contains confidential information and figures referenced in this testimony that BPXA requests be held confidential by the Commission pursuant to AS 31.05.035(d), 20 AAC 25.537(b) and AS 45.50.910 et seq. 2 Written Submittal of A!ploration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F SECTION I BPXA WITNESS This narrative submission is the testimony of Mr. Bruce Laughlin. His business address is 900 E. Benson Blvd., Anchorage, Alaska 99508. Mr. Laughlin received a Bachelor of Science Degree from Pennsylvania State University and a Masters of Science degree from Texas A&M University. Mr. Laughlin's current title at BPXA is Reservoir Management Team Leader. In his present position, Mr. Laughlin supervises BPXA and contract staff focused on delivering long term oil and gas production opportunities for BPXA's PBU assets, including the POP. His team comprises reservoir engineers, geologists and geophysicists. Mr. Laughlin has the training, experience and knowledge relevant and necessary to provide the opinions included in this testimony; in particular as to analytical and dynamic simulation of field depletion mechanisms. Mr. Laughlin has previously testified before the AOGCC as an expert in January 2014 in relation to the "Inquiry Into Gas Liquids Disposition." BPXA respectfully requests that the Commission qualify Mr. Laughlin as an expert in these proceedings in accordance with 20 AAC 25.540(c)(5). Mr. Laughlin will be present, and made available to the Commissioners for questions, at the public hearing on this application to amend POP Rule 9. As noted above, BPXA will provide at least one non -expert witness at the public hearing to testify on the AK LNG Project from BPXA's perspective. That testimony is not included in this filing. SECTION II SUMMARY OF SUBMITTAL A. The Requested Amendment Will Support Progress On The AK LNG Project BPXA and EMAP consider this request to amend the gas offtake rate in Rule 9 of CO 341 D as a significant step for PBU development. The PBU WIOs and the AOGCC have long contemplated a major gas sale project. The participants in the AK LNG Project (which include the State of Alaska and affiliates of BPXA, EMAP and CPAI) have publicly stated that they are progressing plans for an integrated LNG project with a scheduled start-up in 2025. The requested amendment of CO 341 D Rule 9 to increase the maximum annual average gas offtake rate from 2.7 bscf/d to 4.1 bscf/d facilitates that opportunity by providing the flexibility to supply both expected normal and full sustained gas feed rates to the AK LNG Project Gas Treatment Plant ("GTP") from the POP. The AK LNG Project participants have informed the PBU WIOs that the GTP is being designed for sustained receipt of feed gas at the GTP at an annual average rate of 3.5 bscf/d. (The filings by the AK LNG Project with FERC state that the GTP will have an initial gas treating capacity of up to 4.3 bscf/d of feed gas.) BPXA expects that under K Written Submittal of BPRloration (Alaska) Inc. 0 Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F normal operating circumstances, after a one-year operations ramp -up period beginning in 2025, approximately three -fourths of the gas delivered to the GTP is anticipated to be from the POP (2.7 bscf/d) and one-fourth is anticipated to be from Point Thomson or other sources (0.8 bscf/d). (Please refer to AK LNG project draft Resource Reports filed with FERC, cited in the application). To support this level of gas delivery to the GTP from the POP, a minimum annual average gas offtake rate of 3.3 bscf/d from the POP would be required (2.7 bscf/d to the GTP and additional gas offtake of approximately 0.6 bscf/d annual average used for fuel, field operations and minor local gas sales). However, because the GTP is being designed for sustained receipt of feed gas at an average annual rate of 3.5 bscf/d, if the supply of gas to the GTP from the Point Thomson Unit or other sources does not occur as expected or is interrupted, up to 100 percent of the gas supply to the GTP from the POP would be required to maintain uninterrupted gas deliveries to the AK LNG Project. To allow the flexibility for the POP to be the source for up to 100 percent of the feed gas supplied to the GTP in those circumstances, and to avoid disruptions to GTP operations and resulting disruptions to PBU operations that could result from interruptions in a sustained stable supply of gas to the GTP, BPXA and EMAP are requesting AOGCC authorization for a maximum annual average gas off -take of 4.1 bscf/d (3.6 bscf/d to the inlet of the GTP plus 0.5 bscf/d for fuel, field operations and minor local gas sales). Note that in the 100 percent POP case, the feed gas inlet to the GTP must be slightly greater than 3.5 bscf/d to yield an equivalent hydrocarbon gas delivery to the downstream gas offtake points and the LNG liquefaction facility because the CO2 percentage of the POP feed gas stream is greater than in the Point Thomson feed gas stream. The POP fuel gas requirements in the 100 percent POP case drops slightly from 0.6 bscf/d to 0.5 bscf/d since less POP gas is re -injected into the Prudhoe reservoir. A 4.1 bscf/d offtake rate for the POP also would accommodate improved facility performance and allow operational flexibility. The GTP is being designed to receive, treat and ship gas to the liquefaction facility, and to return CO2 by-product to the PBU for injection. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are being requested at this time to support the joint efforts of the State of Alaska and the other participants in the AK LNG Project to progress the project to the front-end engineering and design (FEED) development stage. As more specifically addressed below, modifications of the AIOs are based upon the AK LNG Project design plan for injection of the GTP CO2 by- product into the POP. B. There Is A High Degree Of Confidence In The Current Full Field Model Results The PBU Full Field Model ("FFM") consists of three parts: (i) historical PBU operational data; (ii) a set of reasoned assumptions about future PBU activities; (items (i) and (ii) are collectively referred to as the "FFM Inputs"); and (iii) a BPXA proprietary and trade secret process consisting of software code and algorithms owned by or licensed to BPXA (the "FFM Tool"). Full Field Model runs (sometimes referred to as model scenarios) are generated by inputting the FFM Inputs into the FFM Tool ("FFM Runs"). 4 0 Written Submittal o •BP .f Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F FFM Runs are meant to be predictive of future circumstances or consequences that could occur, depending on the FFM Inputs. Because of the proprietary and trade secret processes that BPXA employs in the use of the FFM Tool, it is not possible to derive the details of PBU operational or technical data (e.g., specific geological data) from FFM Runs. BPXA uses the FFM Tool to generate FFM Runs for both itself and, upon request, for the PBU WIOs. All references in this submission to the FFM are a reference to FFM Inputs plus the FFM Tool. References to and discussions of FFM modeling, scenarios, runs and similar statements are references to FFM Runs. The AOGCC and the PBU WIOs have evaluated and reviewed the potential effects of a PBMGS project on oil production and hydrocarbon recovery from the POP at various stages of field development, most recently in 20071. The PBU WIOs informed and discussed with AOGCC staff, in a series of workshops held earlier this year, upgrades that BPXA has made to the FFM since 2006. Over the past several years the underlying geologic and dynamic data have been extensively reviewed and agreed by the WIOs with the State of Alaska to determine the historic and predictive behavior. The upgrades that have been made by BPXA to the FFM include: increased model resolution; improved and updated well breakage and repair assumptions and data; segregation of drilling by type and area to align assumptions and predictions with potential drilling schedules; use of an improved fuel gas usage algorithm; and improved and updated satellite field flow assumptions and data. Moreover, with substantial updated production and flow history, the FFM history match has been updated to 2014 and improved to include gas cap water injection ("GCWT') impacts on reservoir pressure projections. The updated and recalibrated FFM provides a higher degree of confidence in its predictive capabilities. C. The PBMGS Gas Reference Case The FFM was used to generate an FFM Run of the estimated increase in ultimate hydrocarbon recovery from the POP for a PBMGS case beginning in 2025 and assumed to end in 2055, with a total annual average gas offtake rate of 3.3 bscUd including all uses, (the "gas reference case"), as well as the estimated ultimate hydrocarbon recovery from the POP. BPXA's assessment of the gas reference case is that hydrocarbon recovery is increased by approximately 3.8 billion barrels of oil equivalent ("BOE") or 22 trillion standard cubic feet of gas ("tscf'). Combined with oil, condensate and NGLs production, BPXA's 1 The Commission has long understood that the gas off -take rate in Rule 9 of CO 341 D would have to be revised for major gas sales. See the July 10, 2007 Report Of The Commission Inquiry Into Amending Rule 9 and December 5, 2005 Report On Commission Inquiry Into Potential Revision of Gas Offtake Limit. Written Submittal of BP 1010ration (Alaska) Inc. 0 Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F assessment is that total hydrocarbon recovery from the POP under the gas reference case is approximately 17.7 billion BOE; a net increase of 3.6 billion BOE from the current oil reference case. The details of BPXA's assessment of the gas reference case are discussed in Section V (the Confidential Appendix). D. The PBMGS Full GTP Inlet Supply Case (The Application Request) The FFM was also used to generate an FFM Run evaluating a scenario where the requested total annual average gas offtake rate from the POP of 4.1 bscf/d was applied for an assumed AK LNG Project life of 30 years (i.e., assuming no gas delivery to the GTP from other fields) (the 'full GTP inlet supply case"). This case has been compared to the gas reference case. BPXA's assessment of the full GTP inlet supply case is that slightly more BOEs are recovered than in the gas reference case (17.8 billion instead of 17.7 billion BOEs) due to higher gas recovery that offsets additional impacts on oil production. The details of BPXA's assessment of the full GTP inlet supply case are discussed in Section V (the Confidential Appendix). E. Reference Case Sensitivities The FFM also was used to test the sensitivity of reference case predicted oil and gas recovery to a robust set of alternative assumptions and development scenarios. This type of analysis is often undertaken by BPXA, using its FFM Tool, in conjunction with BPXA and the other PBU WIOs development of specific development plans. Apart from in -place volumes, the most sensitive parameters identified are CO2 injection location (for enhanced hydrocarbon and pressure maintenance), and well breakage. BPXA's assessment of the results of these analyses is that the sensitivity of liquid and total hydrocarbon recovery is negligible (less than 1 percent). The details of BPXA's analysis are discussed in Section V (the Confidential Appendix) F. CO2 Injection into the POP The AK LNG Project participants have indicated that the GTP is being designed to deliver 350 to 450 mmscf/d of CO2 byproduct to PBU for injection. Greater than 90 percent of the total CO2 volume will originate from gas delivered to the GTP from PBU. The additional hydrocarbon recovery associated with PBMGS is 3.8 billion BOE. This additional hydrocarbon recovery is dependent upon CO2 being received at PBU from the GTP. Reservoir studies have been conducted to look at several possible injection locations for enhanced hydrocarbon recovery and pressure maintenance, and initially the Eileen West End ("EWE") area has been identified as the most promising, but the specific location in the POP has not been determined. BPXA and EMAP will continue to work with the PBU WIOs, the Commission and the Alaska Department of Natural Resources to determine one or more locations for injection of CO2 for enhanced no 0 0 Written Submittal ofBP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F hydrocarbon recovery and pressure maintenance. G. Conclusion The POP is the most robust resource on the North Slope, with more than 35 years of production history and operations. BPXA and EMAP are seeking a maximum annual average gas off -take rate of 4.1 bscf/d to allow for the full inlet gas delivery to the GTP and related LNG facilities to be supplied from the POP. This off -take rate will provide BPXA and EMAP, the other PBU WIOs (CPAI and CUSA) and the State of Alaska with flexibility, and allow use of POP gas to cover any gas supply disruptions to the GTP that may occur from other gas supply fields. BPXA and EMAP are also seeking a modification of AIOs 3A and 4F to authorize the injection of CO2 into the POP for enhanced hydrocarbon recovery and reservoir pressure maintenance purposes, from sources both within and outside the PBU. BPXA is confident in the results of the updated and enhanced FFM. BPXA's assessment of the studies and the FFM Runs that have been performed using the FFM is that: (i) total BOE hydrocarbon recovery for the POP is substantially increased with a PBMGS project by approximately 3.8 billion BOE or 22 tscf of gas. Combined with oil, condensate and NGLs production, total hydrocarbon recovery from the POP under the gas reference case is approximately 17.7 billion BOE, a net increase of 3.6 billion BOE from the current oil reference case; (ii) the total BOE hydrocarbon recovery from the POP at the requested full GTP inlet supply case off -take rate (17.8 billion BOE) is comparable to the gas reference case off -take rate (17.7 billion BOE), a difference of less than 1 percent; (iii) ultimate hydrocarbon recovery is relatively insensitive to alternative assumptions and scenarios (less than 1 percent); and (iv) EWE is initially the most promising location for injecting CO2 for enhanced hydrocarbon recovery and pressure maintenance. SECTION III AMENDMENT OF CO 341D RULE 9 TO INCREASE THE MAXIMUM GAS OFF -TAKE TO 4.1 bscf/d IS PRUDENT, APPROPRIATE AND NECESSARY TO PROGRESS THE AK LNG PROJECT A. POP Rule 9 Gas Off -Take Rate CO 341 D Rule 9 limits the maximum annual average gas offtake from the POP to 2.7 bscf/d. Currently, approximately 0.6 bscf/d from the POP is used for fuel, field operations and minor local gas sales. This level of other gas usage is anticipated to VA Written Submittal of BP Mloration (Alaska) Inc. • Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F remain stable. Accordingly, under Rule 9, an annual average gas off -take of approximately 2.1 bscf/d would be available for gas pipeline delivery for major gas sales. This offtake level is not adequate to allow sufficient gas delivery from the POP to the AK LNG GTP for PBMGS. (Please note that unless otherwise indicated, references to AK LNG public statements in this submission are to the draft Resource Reports filed with FERC as referenced in the application.) 1. AK LNG Project The participants in the AK LNG Project, including the affiliates of both BPXA and EMAP and the State of Alaska, have informed the PBU WIOs that the design of the AK LNG facilities is premised on a sustained annual average gas supply rate of 3.5 bscf/d to the GTP. (AK LNG Project participants have publicly stated that the GTP will have an initial gas treating capacity of up to 4.3 bscf/d of feed gas.) The AK LNG Project participants have also publicly stated that the GTP is being designed to receive, treat, and ship gas to the Liquefaction Plant, and to return for reinjection into the POP the by- product primarily consisting of CO2. 2. POP Gas Supply to AK LNG The AK LNG Project participants have publicly stated that under normal operating circumstances, they anticipate that —3/4 of the feed gas to the GTP (2.7 bscf/d) will be from the POP, and the remaining 1/4 of the feed gas (0.8 bscf/d) will be from Point Thomson or other sources. BPXA and EMAP together will provide approximately 69 percent of the total hydrocarbon resources from these fields to the AK LNG Project. BPXA and EMAP's assessment is that the POP will be able to deliver gas to the GTP for 30 years under this scenario. 3. Amendment of Rule 9 CO 341 D Rule 9 limits the maximum annual average gas off -take from the POP to 2.7 bscf/d. Currently, approximately 0.6 bscf/d of gas from the POP is used for fuel, field operations and minor local gas sales. This level of other gas usage is anticipated to remain stable in the future. Therefore, the current 2.7 bscf/d off -take limit is insufficient to meet the gas delivery inlet capacity of the AK LNG GTP under even normal operating conditions, which assume delivery of 0.8 bscf/d from Point Thomson or other sources (current POP offtake limit of 2.7 bscf/d minus 0.6 bscf/d gas for fuel, field operations and minor local sales only allows 2.1 bscf/d to the GTP, which combined with 0.8 bscf/d from Point Thomson or other sources does not meet AK LNG Project design for a sustained annual average gas supply rate of 3.5 bscf/d of feed gas to the GTP). Under the circumstance where gas delivery to the GTP from Point Thomson and other sources does not occur as expected or suffers a supply interruption, a total gas offtake of 4.1 bscf/d would be required from the POP (3.6 bscf/d to the GTP + 0.5 bscf/d for fuel, field operations and minor local sales) to allow the full supply of inlet gas supply to the 8 • 0 Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341D Rule 9 and AIOs 3A and 4F GTP. B. Full Field Model And Data Improvements BPXA has made many updates to the FFM since the AOGCC last considered analyses of a PBMGS in 2007. The following is a high level summary of those updates. Section V of the Confidential Appendix contains a comprehensive and more detailed discussion of these confidential FFM improvements. BPXA has continuously updated the FFM since its original development. Over many years of historical production and development updates, the model continues to narrow the assumptions and improvement needs. The physical constraints associated with facility limits, pipeline networks, drilling and well work activity all contribute to better understanding of the shape of the model and the property distribution. With improved computer processors, refinements to the grid resolution have given better understanding to the flow characteristics between wells. The FFM has been used internally by BPXA to inform its analysis, from a PBU WIO perspective, of drilling projects, the gas cap water injection project, surface facility debottlenecking projects, as well as previous PBMGS analyses. BPXA has also provided FFM Runs to the PBU WIOs to inform their analysis of similar projects. As a result of these FFM refinements and updated data, BPXA's assessment of the FFM is that the current history match predicts each fluid phase within 1 percent of actual field data. Therefore, BPXA considers the current FFM to be highly reliable. C. FFM Assumptions And Analyses In order to assess hydrocarbon recovery for a PBMGS development scenario compared to an oil production scenario, a reference case set of assumptions was developed and incorporated in the FFM to reflect both sound engineering principles and a development program that recognizes economic considerations. The following is a high level summary of those assumptions. Section V of the Confidential Appendix contains a comprehensive discussion and details of these assumptions. In order to perform a valid analysis of the benefits for PBMGS, the model requires assumptions about both oil -focused operations and a PBMGS. In this analysis, the following assumptions were made for the oil reference case and the gas reference case. 1. The Oil Reference Case The oil reference case assumed the following activities will continue. Among these assumptions are activities that have been implemented with the view toward PBMGS. • Active development drilling program • Rig workovers to maintain healthy well stock I Written Submittal of BPPloration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F Continued Gas Cap Water Injection Normal Turnaround activities for facility maintenance 2. The PBMGS Gas Reference Case The gas reference case includes many of the same activities assumed for the oil reference case. The reason for these assumption sets to be the same is to give a more valid consideration of the benefits on a like -for -like comparison. There are certain additions to the assumptions that must be incorporated to manage a gas analysis. The following are the assumptions associated with the gas reference case. • Same development drilling program as the oil reference case • January 2025 gas sales startup date with a 1 year ramp to full delivery • Annual average gas supply to the GTP —2.7 bscf/d • Normal annual turnaround maintenance events • GTP by-product CO2 injected into the Eileen West End of the POP • Conversion of the apex gas injectors to gas producers late in project life • Rig workovers to keep healthy well stock until the end of the project • Perforations to add gas production to the project • 30 year total project life As noted earlier, the gas reference case shows PBMGS will increase ultimate hydrocarbon recovery from the POP by approximately 22 tscf or 3.8 BOE. 3. The PBMGS Full GTP Inlet Supply Case Comparison The full GTP inlet supply case incorporates one change. The annual average gas supply to the GTP is increased from —2.7 bscf/d to a rate of 3.6 bscf/d. (3.6 bscf/d is used because the gross inlet volume of gas will be slightly higher in this modeled case due to the higher CO2 content in POP gas compared to the blended gas stream expected from other gas fields.) As noted earlier, the full GTP inlet supply case recovers slightly more BOEs than the gas reference case (17.8 instead of 17.7 billion BOEs) due to higher gas recovery that offsets additional impacts on oil production. 4. Impacts of Sensitivities The impacts of the sensitivities on gas sales, oil recovery and BOE recovery were evaluated. Apart from in -place volumes, the most sensitive parameters identified are CO2 injection location (for enhanced hydrocarbon and pressure maintenance), and well breakage. All of the other sensitivities have less than a 5 percent impact on total BOE recovery, with most sensitivities having a negligible impact (less than 1 percent impact). The impacts on gas production from the sensitivities tested have a greater effect on ultimate BOE recovery than the nominal positive impacts to oil recovery. These results 10 Written Submittal ofAxploration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and A10s 3A and 4F are discussed in Section V (the Confidential Appendix). SECTION IV MODIFICATION OF AIOS 3A AND 4F INJECTION OF CO2 FROM SOURCES WITHIN OR OUTSIDE OF PBU FOR ENHANCED HYDROCARBON RECOVERY AND PRESSURE MAINTENANCE A. AK LNG CO2 Byproduct Return The AK LNG Project participants (including affiliates of BPXA, EMAP and CPAI, and the State of Alaska) have informed BPXA that gas shipped through the AK LNG system pipelines to the liquefaction facility will need to be treated in the GTP to a CO2 specification of 50 ppm or less. AK LNG Project participants have publicly stated that the GTP is being designed on the basis that the byproduct from gas treated at the GTP, which BPXA expects will be dry and approximately greater than 99 percent CO2, will be transported to the PBU for further handling. See Figure 1 below for a conceptual depiction of a CO2 distribution system. Conceptual CO2 receipt Coe Control and distribution system module CGy G 5 miles CO2 from GTP APEX PL t� 1 miles) GC-2 GC-1 .... 3 miles 2 mies 3 mi es 72m4e GC-3 WPZ WP W Figure 1 CO2 Distribution System B. Amendment of AIOs The AK LNG Project participants inform us that the GTP may deliver an annual average of 350 to 450 mmscf/d of CO2 byproduct to PBU for injection. Greater than 90 percent of the total CO2 volume will originate from gas delivered from PBU. AIOs 3A and 4F, however, currently only permit injection of gas (which includes the CO2 entrained in the gas) that is sourced from PBU gas processing facilities. The additional hydrocarbon recovery associated with PBMGS is 3.8 billion BOE. This 11 Written Submittal of BP *oration (Alaska) Inc. • Application for Amendment of POP CO 341 D Rule 9 and AIOs 3A and 4F additional hydrocarbon recovery is dependent upon the ability of PBU to receive CO2 from the GTP. Although the specific location for injection is still being evaluated, analysis of CO2 injection in POP shows there will be enhanced hydrocarbon recovery and pressure maintenance benefits. BPXA is therefore seeking a modification of AIOs 3A and 4F to authorize the injection Of CO2 into the POP for enhanced hydrocarbon recovery and reservoir pressure maintenance purposes, from sources both within and outside the PBU. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are requested at this time to support the joint efforts of the State of Alaska and the other AK LNG Project participants to progress the AK LNG Project to the front-end engineering and design (FEED) development stage. Amendment of the AIOs at this time will also allow the PBU WIOs to pursue related PBU activities supporting this injection of GTP CO2. C. Assessment of CO2 Injection Various locations within the POP were evaluated to determine the hydrocarbon recovery associated with injection of CO2. These areas included the Gas Cap, Flow Station 2 area and Eileen West End. In past evaluations of PBMGS, the gas cap was considered as an option. Lower CO2 handling limits into the GTP and the rapid increase in CO2 from the POP that would occur demonstrates that this location is a less viable option given the impact on hydrocarbon recovery. The Flow Station 2 area was also evaluated and this area remains a potential location due to the availability of the miscible injection distribution system. Compared to the more promising Eileen West End location, the FS2 area was also determined to have higher returned CO2 concentrations and lower hydrocarbon recovery. Eileen West End provided the highest benefit from a hydrocarbon recovery perspective when compared to the other injection locations. Due to the large volume of CO2 that is currently injected into the POP through day to day operations as part of the overall gas reinjection stream (about 800 mscf/d), the volume of CO2 injected during PBMGS is essentially the same. The benefits of this injection are associated with increased pressure to the reservoir, thus improving oil recovery throughout the field and recovery of Miscible Injectant ("MI") currently trapped in the EWE area of the field. This MI can be utilized for additional FOR benefits. 12 0 0 Written Submittal of BP Exploration (Alaska) Inc. Application for Amendment of POP CO 341 D Rule 9 and AlOs 3A and 4F OATH BPXA requests that the Commission authorize and recognize this submission as pre -filed written public testimony in support of its application. Based upon my expertise, knowledge, information and belief formed after reasonable inquiry, I certify and swear that the statements and information in Sections II through V of this submittal, including in the Confidential Appendix to this submittal, are true and accurate. ��' Bruce Laughlin BP Exploration (Alaska), Inc. 13 Appendix held confidential in secure storage ConocoPhillips Alaska August 19, 2015 Catherine P. Foerster, Commission Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Ave #100 Anchorage, Alaska, 99501-3539 AU(a 19 2015 Jon Schukz Manager Greater Prudhoe Area P.O. Box 100360 Anchorage, AK 99510-0360 Phone: 907-265-1315 RE: Docket Numbers: AIO 15-032, AIO 15-033, CO 15-09 — Prudhoe Bay Unit ConocoPhillips Comments to BP Exploration (Alaska) Inc. (BPXA) and ExxonMobil Alaska Production, Inc. (EMAP) July 17, 2015 Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Commissioner Foerster, ConocoPhillips Alaska, Inc. (CPA[) submits, on behalf of itself and Chevron U.S.A. Inc. (CUSA), both Prudhoe Bay Unit (PBU) working interest owners, the following comments to the above -referenced application (BPXA and EMAP Consolidation Application), and respectfully requests that the Alaska Oil and Gas Conservation Commission (Commission): (i) Approve BPXA's and EMAP's request to increase the Rule 9 maximum allowable gas offtake rate, but to a maximum offtake rate of 3.6 billion standard cubic feet per day (bscf/d) annual average, rather than the 4.1 bscf/d annual average requested by BPXA and EMAP; (ii) Approve BPXA's and EMAP's request to modify relevant area injection orders to permit injection of carbon dioxide (CO2) and other gas treatment byproducts for purposes of enhanced oil recovery (EOR) and pressure maintenance; and, in addition to BPXA's and EMAP's request, also approve injection of CO2 and other gas treatment byproducts for disposal in appropriate intervals, in the event that FOR or pressure maintenance opportunities that result in increased POP hydrocarbon recovery are not identified; and (iii) Include in Rule 9 and relevant area injection orders provisions, as necessary, to permit administrative approval of future modifications. CPAI Comments to BPXA and AP Consolidated Application to AmendRule 9 and Modify AIOs Page 2 of 6 August 19, 2015 A. CPAI Supports BPXA's and EMAP's Request to Increase the Rule 9 Maximum Allowable Offtake Rate, But Requests the Commission Approve a Rate — 3.6 bscf/d — Commensurate With the AKLNG Design Basis and Reasonably Expected Gas Volume Needs As the Commission is aware, CPAI has been working closely with the other PBU working interest owners (WIOs), to support a request to the Commission to increase the current 2.7 bscf/d annual average Rule 9 maximum gas offtake rate for the Prudhoe Oil Pool (POP), as an important part of making possible potential major gas sales from PBU through the Alaska LNG Project (AKLNG). Affiliates of BPXA, EMAP and CPA[, together with agents of the State of Alaska, have advanced AKLNG pre -FEED engineering, and AKLNG is expected to enter FEED' next year. Increasing the Rule 9 maximum annual average offtake rate will provide additional certainty to support an AKLNG FEED decision, as well as subsequent decisions to construct and operate AKLNG. In this regard, CPAI always has supported, and continues to support, requesting that the Commission increase the Rule 9 maximum allowable POP offtake rate. As the Commission likely is aware, until June, CPAI supported considering an increase to the maximum annual average POP offtake to 4.1 bscf/d, where that daily rate would be available if the PBU WIOs determined to supply additional gas to the AKLNG gas treatment plant (GTP), in the event of a temporary non -POP gas supply disruption. As explained below, after further consideration, CPAI has determined that 3.6 bscf/d annual average POP offtake is more than sufficient to accommodate full AKLNG GTP supply from the POP for the full duration of any reasonably expected non -POP gas supply disruption. Accordingly, CPAI requests that the Commission approve 3.6 bscf/d as the Rule 9 maximum allowable annual average POP offtake rate. 1. Governor Walker's June 8 Letter Defined Reasonable Expectations For the Duration of Non -POP Gas Supply Disruption On June 8, Governor Walker sent a letter to BPXA, EMAP and CPAI. The Governor shared the June 8 letter with the Alaska Legislature on June 15.2 The Governor's letter provided helpful clarity regarding necessary gas supply terms to support AKLNG, including the duration of potential non -POP gas supply disruption. Appendix A of the Governor's June 8 letter lays out a preferred commercial structure comprised of two joint ventures: one receiving PBU gas and one receiving PTU gas (PTU being the non -POP gas supply source to AKLNG), and treating, transporting and liquefying the gas through AKLNG capacity reserved for each source of supply. Appendix A notes that the Prudhoe Bay joint venture and the Point Thomson joint venture may enter into certain mutual aid arrangements: one month of mutual aid per year, in case of downtime caused by operational issues; and two months of mutual aid on a one-time basis, in case of severe disruption. This proposal from the Governor defined reasonable expectations regarding maximum durations over which 100% POP offtake rate could be required: at most, one month on an annual basis; at most, two additional months, in case of once -in -field -life emergency. These maximum durations are conservative, safe assumptions, well in excess of typical industry or North Slope downtimes. So far as CPAI is aware, no major North Slope field ever has experienced an operational issue that caused the field to be entirely offline for three months. The longest major shutdown of which ' Front -End Engineering and Design (FEED) is the final engineering phase before AKLNG sanction, or final investment decision (FID). The AKLNG parties are expected to determine whether to enter FEED in 2016, and to determine whether to approve FID in 2019. 2 The Governor's June 15 and June 8 letters are Attachment 1 to these comments. CPAI Comments to BPXA angMAP Consolidated Application to Amend Pule 9 and Modify AIOs Page 3 of 6 August 19, 2015 CPAI is aware occurred in October 2006 when approximately 30% of PBU production was shut in for 82 days, due to transit line issues. 2. 3.6 bscf/d Is the Appropriate Maximum POP Offtake Rate At This Time Taking into account the AKLNG design basis, premised POP and non -POP AKLNG supply, reasonable expectations regarding PTU downtime, minimization of PBU liquid impacts, and the basic premise that 4.1 bscf/d could be used as an excursion rate, available if the PBU WIOs determined to supply additional gas to the AKLNG GTP, in case of a temporary non -POP gas supply disruption, 3.6 bscf/d is the appropriate maximum annual average POP offtake rate at this time. 3.6 bscf/d annual average maximum offtake provides more than sufficient capacity, even in case of a worst - case 3 month period of 100% PTU downtime in a single year. In fact, a maximum annual average offtake of 3.6 bscf/d would allow for the PBU WIOs to supply 100% of AKLNG GTP inlet volume for approximately 4 months in one year.3 3. 3.6 bscf/d Annual Average Offtake Is More Than Sufficient for AKLNG AKLNG FEED is estimated to cost approximately $2 billion. Accordingly, the decision to enter FEED will require certainty on many issues to support such a large commitment. The current shared goal of BPXA, EMAP and CPAI is to secure an increase to the current Rule 9 maximum allowable offtake rate from the POP, to provide certainty regarding available POP gas, which would be a key factor supporting a 2016 AKLNG FEED decision, as well as subsequent decisions to build and operate AKLNG. A 3.6 bscf/d annual average rate would provide more than sufficient certainty regarding POP gas availability, based on reasonable expectations of maximum PTU downtime in any year. 4. The Commission Should Defer Consideration of an Offtake Rate Higher Than the 3.6 bscf/d Annual Average Rate Required for AKLNG The 3.6 bscf/d annual average POP offtake rate will be more than sufficient to supply AKLNG. However, if AKLNG does not proceed, and if another gas commercialization project is later developed, with different gas sources, or a different basis of design, then it would be appropriate for the Commission to reevaluate POP offtake in light of that new technical information, and then -current POP reservoir and other information. 5. PTU Is Premised to Provide 25% of the Gas to AKLNG; However, If PTU Start Up Is Materially Delayed or PTU Resources Are Materially Less Than Predicted, There Will Be More Than Sufficient Time to Amend the POP Offtake Rate, If Appropriate BPXA's and EMAP's application states that additional POP rate may be required "during startup of, or after gas production begins to decline from, other fields".4 CPAI does not entirely understand this statement. It may suggest that BPXA and EMAP perceive a real risk that PTU start-up will be materially delayed, after AKLNG start-up currently premised in 2025. CPAI also is a PTU owner, and is not aware of such a risk, especially in light of the extent of work that will have been completed by next year for IPS. As far as CPAI is aware, excepting TAPS, no North Slope project similar to (or larger than) PTU gas expansion has been delayed more than 3 months. Further, given the complexity and scope of AKLNG (currently estimated to 3 CPAI's requested 3.6 bscf/d POP maximum annual average offtake rate is comprised of 2.7 bscf/d normal AKLNG GTP supply, 0.6 bscf/d for fuel gas, other field operations, and minor North Slope sales, plus 0.3 bscf/d to allow for the POP to supply 100% of AKLNG GTP inlet volume for up to four months in one year. In this regard, if POP offtake occurred at 4.1 bscf/d for 4 months, and at 3.3 bscf/d for 8 months, then the annual average offtake rate would be approximately 3.6 bscf/d. 4 BPXA and EMAP Consolidated Application, at 4. E CPAI Comments to BPXA and MAP Consolidated Application to Amende 9 and Modify AIOs Page 4 of 6 August 19, 2015 cost $45-$65 billion), it is much more likely that AKLNG — not PTU — would be the source of any material start-up delay. However, if AKLNG did start-up in 2025, and if PTU start-up were materially delayed after AKLNG start up, and the PBU WIOs wished to supply the AKLNG GTP during the period of PTU delay, CPAI anticipates the Commission could timely consider a short term increase to the Rule 9 offtake rate at that time. As construction progress will be closely tracked against critical path schedules, the PBU WIOs would know likely at least one year in advance if PTU start up would be delayed more than four months.5 In any event, given the low likelihood of material PTU delay — a successful AKLNG project is premised on simultaneous start-up of all project and related upstream systems — there is no need for the Commission to grant a POP annual average offtake rate higher than 3.6 bscf/d at this time. The same is true if, in relation to BPXA's and EMAP's statement that additional POP supply may be required "after gas production begins to decline from ... other fields" .6 This statement appears to suggest that if PTU declines much faster than expected, supply from the POP will be needed to cover the difference. As far as CPAI is aware, this is unlikely. The PTU operator has provided very high quality information validating PTU resources. The IPS Project will provide additional validation. CPAI expects there will be a low likelihood that PTU will decline much faster than anticipated. However, in the unlikely event that PTU declines much faster than expected, and the PBU WIOs wished to supply additional gas from the POP, there would be sufficient time to request an appropriate Rule 9 increase.7 AKLNG start-up currently is premised to occur in 2025. Accelerated PTU decline, if it were to occur, would occur many years after 2025 start-up. In sum, material PTU delay and materially accelerated PTU decline are both unlikely events. If either ever occurred, a PBU offtake increase could be timely considered by the PBU WIOs and the Commission, if appropriate, at that time. B. CPAI Supports BPXA's and EMAP's Request to Allow GTP Byproduct Injection for FOR and Pressure Maintenance, But Further Requests That the Commission Allow Disposal of GTP Byproducts in Appropriate Intervals Through Class II Wells CPAI supports BPXA's and EMAP's request to inject GTP byproducts, principally comprising CO2, into appropriate intervals within the PBU, for FOR and pressure maintenance. However, CPAI notes that the benefit BPXA and EMAP identify in connection with such injection — approximately 3.8 billion barrels of oil equivalent — is the total gas recovery associated with major gas sales into AKLNG.8 This additional recovery is very material, but it is not an FOR benefit. BPXA and EMAP have not identified actual FOR benefits in their application.9 However, AKLNG start up is premised to occur in 2025, so there are many years in which to investigate additional FOR opportunities. In this regard, CPAI requests that the Commission grant BPXA's and EMAP's 5 Further, unless AKLNG start up is to occur on the first of a calendar year, a 3.6 bscf/d maximum offtake rate would allow offtake from the POP at 4.1 bscf/d for longer than four months in that year (as the daily rates are averaged over the entire calendar year), which would afford additional flexibility. 6 BPXA and EMAP Consolidated Application, at 4. CPAI requests that the Commission include, as necessary, provisions in Rule 9 and relevant area injection orders to permit administrative approval of future modifications. 8 BPXA and EMAP Consolidated Application, at 5. 9 The Consolidated Application does not identify "an expected increase in incremental hydrocarbon recovery" from CO2 injection. 20 AAC 25.402(c)(14). • CPAI Comments to BPXA and EMAP Consolidated Application to Amend Rule 9 and Modify AIOs Page 5 of 6 August 19, 2015 request to approve GTP byproduct injection for FOR and pressure maintenance, in anticipation that there may be FOR opportunities later identified. However, in the event that FOR opportunities are not later identified, CPAI also requests that the Commission approve disposal of GTP byproduct in appropriate intervals in Class II PBU wells.10 C. Supporting Information CPAI will have appropriate experts available at the public hearing to testify regarding these comments. Depending on the testimony presented by others, CPAI reserves the right to present additional testimony at the public hearing, or by post -hearing submission, if so authorized by the Commission. D. Conclusion Based on the above comments, CPAI respectfully requests that the Commission: (1) Approve BPXA's and EMAP's request to Increase the Rule 9 maximum allowable offtake rate, but to a maximum offtake rate of 3.6 bscf/d annual average, rather than the 4.1 bscf/d annual average requested by BPXA and EMAP; (il) Approve BPXA's and EMAP's request to modify relevant area injection orders to permit injection of CO2 and other gas treatment byproducts for purposes of FOR and pressure maintenance; and, in addition, also approve injection of CO2 and other gas treatment byproducts for disposal in appropriate PBU Intervals, in the event that FOR or pressure maintenance opportunities that result In increased POP hydrocarbon recovery are not identified; and (III) Include in Rule 9 and relevant area injection orders provisions, as necessary, to permit administrative approval of future modifications. Please contact Eric Reinbold at 907-263-4465 if the Commissioners or Commission staff have any questions regarding these comments. Please direct communications regarding procedural matters, including the public he;ring, to John Evans, counsel for CPAI, at 907-265-6329. Sincerely, , Greater Prudhoe Area 1, Inc. Concurring for Chevr S.A. Inc. J.M7WoliVer, NOJV Manager Chevron North America Exploration and Production Company, a division of Chevron U.S.A. Inc. 10 CPAI recognizes that the Commission will need additional information under 20 AAC 25.262 to approve a disposal request; however, this information can be readily provided by the PBU operator. Relevant to 20 AAC 25.252(c), as noted in BPXA's and EMAP's Consolidated Application, there is no risk of movement of fluids into sources of freshwater or underground drinking water. BPXA and EMAP Consolidated Application at 6. CPAI Comments to BPXA anc�'"EMAP Consolidated Application to Amend Mule 9 and Modify AIOs Page 6 of 6 August 19, 2015 Attachment 1 — June 15 and June 8 Letters from the Governor of the State of Alaska cc via email. - Gilbert Wong, EMAP (gilbert.wong(cbexxonmobil. com) Steve Luna, EMAP(charles.s.luna(o-)-exxonmobil.com) Phil Ayer, CUSA (pmayer(aD-chevron.com) Angie Bible, CUSA (abible(o-)_chevron.com) John Dittrich, BPXA (John. Dittrich(obp.com) George Lyle, Guess & Rudd (gllyle(a)-guessrudd.com) Chris Wyatt, BPXA (Chris.Wyatt(a)bp.com) Eric Reinbold, CPAI (Eric.W.Reinbold(3conocophiHips. com) John Evans, CPAI (John.R.Evans(a�conocophillips.com) • 0 Attachment 1 June 15 and June 8 Letters from the Governor of the State of Alaska See attached. STATE CAPITOL P.O. Box 110001 =� Juneau, AK 9981 1-0001 907-46S-3500 fax: 907-46S-3532 Governor Bill Walker STATE OF ALASKA June 15, 2015 The Honorable Kathy Giessel Alaska State Senate 716 W. 4th Ave. Suite 511 Anchorage AK, 99501 The Honorable Benjamin Nageak Alaska State House of Representatives State Capitol Room 126 Juneau AK, 99801 The Honorable Dave Talerico Alaska State House of Representatives 1292 Sadler Way Suite 328 Fairbanks AK, 99701 Dear Senate and House Resource Committee Chairs and Co -Chairs: 550 West Seventh Avenue, Suite 1700 Anchorage. AK 99501 907-269-7450 fax 907-269-7461 www.Gov.Alaska.Gov Governor@AJaska.Gov I want to inform you about the efforts of my administration to move the AK LNG project ahead. Attached is my letter dated June 8, 2015 to the heads of the producers' negotiating teams for the AK LNG project. We have identified a lack of urgency in the parties' resolution process. The methodology that the AK LNG team adopted for identifying problems and issues is excellent. However, there does not appear to be much process associated with resolving issues between the parties, and certainly not one with a sense of time urgency. It is time to build this gas pipeline to Nikiski, and therefore the state needs to take the lead and proactively mediate and find resolutions within a time frame that will keep the project on schedule. The attached letter proposes a time frame and process for moving the issues to resolution. To date, the producers have been working towards a 2"a quarter-2016 FEED decision. This meshes efficiently with a fall special session for legislative review of the proposed agreements. It also works well should voter consideration of a November 2016 constitutional amendment be required in addressing the fiscal certainty needs of the project. For these reasons, schedules should not be allowed to slide. Assuming that all the producers match the State's commitment to commercialize North Slope gas, we must push ourselves to close out these issues. The attached letter identifies the key issues requiring resolution and the state's position on those issues. My hope is that with clarity of focus and attention, the producers and the state can stay the course on their intended timeline and give Alaskans a gas pipeline project from the North Slope to Nikiski that will provide the next generation the revenues they need to build a prosperous future. • • Sincerely, �$illX�alker Governor cc: Janet Weiss Dave VanTuyl Joe Marushack Pat Flood Bill McMahon Jim Flood • • STATE CAPITOL 110 Box 110001 Juneau. AK 9981 1 -0001 907-465-3500 fax: 907-465-3532 Governor Bill Walker STATE OFALASKA June 8, 2015 Janet Weiss & Dave VanTyle BP Exploration Alaska, Inc. 900 E. Benson Blvd. Anchorage, AK 99508 Joe Marushack & Pat Flood ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Bill McMahon & Jim Flood ExxonMobil Development Company Wellness 2, 5A.345 22777 Springwoods Village Parkway Spring, Texas 77399 Dear AK LNG Sponsors: S50 West Seventh Avenue, Suite 1700 Anchorage, AK 99501 907-269 7450 fax 907-269-7461 www.GovAlaska Gov Governor@Alaska.Gov A few weeks ago, we jointly set a goal to finalize the term sheets for all major project enabling contracts by the middle of June. It is now June 8th. Despite the efforts of all parties, it is clear we are not on schedule to achieve this goal. There are at least two major issues and at least three smaller major issues. I have summarized the State's listing of those issues along with my comments. I am asking that this list be considered by the VAMOU on Tuesday to determine if consensus can be reached on the completeness of the list. The goal would be to gain agreement on a final list of major issues in order for our respective negotiating teams to share a common focus and issue prioritization. The resulting list would then be presented at the Sponsor Meeting on Wednesday with the Sponsor representatives tasked to resolve these major issues — especially the two large major issues. Resolution of these major sticking points will be a catalytic event enabling substantial progress on finalizing the terms of the project contracts. To the extent there are issues remaining after the Sponsor Meeting where the parties are substantially apart, I would like the State to engage in a shuttle diplomatic effort with producers, with a goal of gaining issue closure or at least a clear understanding of the extent of remaining disagreement. Following the best efforts of our teams to reach closure on the major issues, I 0 • would like to meet face to face during the week of June 15th with each Sponsor executive individually to attempt to resolve the remaining issues. I would like to resolve the major issues in these meetings so we can begin the process of drafting contracts The AK LNG team will be briefing the Legislature on the 161h of June in Kenai, Alaska. After months of expectation, the people of Alaska and their elected representatives are anxious for concrete progress. Large Major Issues 1. The largest issue is Joint Venture Marketing vs. Equity Marketing, The State believes it will be very difficult, if not impossible, for this project to proceed with the PBU and PTU fields with all the current participants outside a Joint Venture Marketing context. 2. Upstream issues — to the extent they are not resolved by Joint Venture Marketing. Most of the remaining upstream issues can be resolved through the use of separate Joint Ventures that would receive the gas from the PBU and PTU fields with support between the two Joint Ventures along the lines of the proposal attached as Appendix A. Other Major Issues 3. Fiscal Stability: It will only deal with the gas dedicated to this Project from PBU and PTU. It will not include oil. The State is willing to consider a 25 year term in order to facilitate integrated project financing. The State believes a Constitutional Amendment will provide the certainty that all parties would like. Attached as Exhibit B is an example of what I envision the constitutional amendment might look like. 4. 48 inch line: Constructing a 48 inch line will alleviate the issues of open access and expansion. The Producers have stated they do not need or want a 48 inch line. The State is willing to pay for this expansion subject to legislative approval, but it would own all the benefits of the increased size. The State would also pay for installing the valves, pads etc. to accommodate four more compressor stations that will be added when demand exists from new developments or fields. The State intends to use this expansion capacity to encourage open access. 5. East vs. West Cook Inlet crossing: It is my understanding that the studies for the two routes are under way but that the tentative conclusion at this point in time is that the Western Route is the preferred alternative. The Matsu Valley constitutes the second largest population base in the State of Alaska and has some of the highest industrial potential in the State. Consequently, the State strongly prefers the Eastern Route since the studies to date do not indicate any insurmountable obstacles. Also, the Eastern Route will better enable this Project to better fulfill the statutory domestic gas mandate. • C� Sincerely, Bill Walker Governor Enclosure Appendix A — Joint Venture Marketing Model Appendix B — Sample Draft Constitutional Amendment cc: Dona Keppers, SOA, Deputy Commissioner of Revenue Dan Fauske, AGDC Steve Wright, SOA, Department of Natural Resources Audie P. Setters, SOA, Gas Team, General Manager • Joint Venture Marketing Model Appendix A PB Capacity MMM" Future Mutual Aid I PT Capacity AKLNG Less complex than any acceptable FSA solution proposed to date • Can explain to buyers, lenders and other State stakeholders Market Perception of AKLNG AKLNG JV Buyers -LNG -LNG -in State -In State Note: Each party to verify that any marketing structure contemplated for AKLNG complies with applicable anti-trust laws • The JV revenue flows back to Titleholders in proportion to their respective participation • Any JV costs (including SPA penalties) flow back to Titleholders in proportion to their respective participation • The JV nominates supply from each Unit, and takes title at entry point to the relevant Transmission Line Gas Balancing and Mutual Aid: iOne month of borrow/loan gas each year for operational issues: • to be repaid in kind within one calendar year; • In place for 15 years after start-up • One time gas purchase option (approx. 2 months of PTU downtime): • 80 BCF (20 cargos) on an energy basis • Expires lesser of 5 years after triggered or year 15. • Ns can "bank" gas to ensure access to additional future gas; • Good faith mutual assist provision to ensure Ns avoid reputational damage to AKLNG (dropped cargos) 1 • 0 0 • APPENDIX B Sample Draft Constitutional Amendment * Section 1. Article IX, Constitution of the State of Alaska, is amended by adding a new section to read: Section 18. Suspension of Taxation by Contract Authorized by Law. Contracts approved by a majority of the legislature and entered into by the executive branch by December 31, 2017 to provide fiscal terms for a liquefied natural gas project, including a gas treatment plant, gas pipelines, and a liquefied natural gas plant and related facilities, as provided by law are constitutional under this article. Such contracts as originally executed shall be binding upon future legislatures as to terms of gas taxation, but any amendments to such contracts executed between the parties shall not bind future legislatures as to any aspect of taxation. • REVISED Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC previously scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7 h Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 41h Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 71h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.tv. 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 793-1221, no later than August 20, 2015. Cathy P. oerster Chair, Commissioner u • STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE 3HOWPIG ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTSMENT. ADVERTISING ORDER NUMBER A O-16-004 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/23/15 1(907) AGENCY PHONE: 793-1221 333 West7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICF. Revised AIO-15-032, AIO-033 and CO-15-09 Initials of who prepared AO: Alaska Non -Taxable 92-600185 sv 6iyiiT li�zliQldT sitQviv�:AKTs1tTiSilkG ;:O;IjI)$R�jNO.� CERTIFIED �F#RA�: QF: : r.UsiicpiioN;wiii[:ATtzcliEu;ciiP:Yoi?: Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of I Total of All Pa es $ - REF Type Number Amount Date Comments I PVN ADN84501 2 Ao AO-16-004 3 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST LIQ 1 16 02140100 73451 1 16 2 3 4 5 n Purchas g u ,me: itie: 1 uIc r hority's Signa ure Telephone Number 1. A.O. # a receiving agency name st app on all invoices and documents rel ing to this purchase. 2. The stat j registered for tax free transactions under Chapter 32, IRS code. Reg ration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. I?ISTRIB. . . ::: ➢ivt .... F..... Drt" al A© ;" Co Ie3 ; Publisher cal R IYI e eel In Form:02-901 Revised: 7/23/2015 270227 0001368912 $ 194.24 13ECEIVED AUG 0 3 2015 AFFIDAVIT OF PUBLICATION "4OGCc STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch 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 July 24, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed`�� r Subscribed and sworn to before me this 24th day of July, 2015 /� /1 /-h, /l . / '—) ). c-. - — I —%:C ^-� - Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES �-�L23(12oa Revised Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Docket Numbers: AIO 15-032, AID 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341 D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC previously scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue. By this revised noticed, the site of the public hearing is changed to 716 West 4th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 hearing. If you would like to attend the above Public Hearing but are unable to do so in person, the call in number is 1-844-586-9085 or you can watch live at akl.ty. 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 793-1221, no later than August 20, 2015, Cathy P. Foerster Chair, commissioner AO-16-004 Published: July 24, 2015 �o"city P�"tlic iRiTNEY L, THOMPSON State of Alaska MY GOAtmi111on Expires Feb 23, 2019 Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, July 23, 2015 2:32 PM To: Ballantine, Tab A (LAW); 'Salena'; Delbridge, Rena E (LAS); glyle@guessrudd.com; AKDCWeIIIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew Vanderlack, Anna Raff; Barbara F Fullmer, bbritch; Becca Home; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek, Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker; Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky, Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos, Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline J; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke; Ballantine, Tab A (LAW); Bender, Makana K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, 0 • To: Angela K (DOA); Wallace, Chris D (DOA) Subject: Revised Public Notices Attachments: Revised Notice of Public Hearing, CO-15-08.pdf; Revised Notice of Hearing, Dockets AI0-15-32, AI0-15-33, CO-15-09.pdf Please disregard the Public Notices that I sent earlier, the website information was incorrect. I apologize for any inconvenience this may have caused you. Bernie Karl James Gibbs Jack Hakkila K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 P.O. Box 58055 Soldotna, AK 99669 Anchorage, AK 99519 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Dave P. Lachance Vice President Richard Wagner Darwin Waldsmith Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 Angela K. Singh E • Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 4F, and Conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC has scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 71h Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 71n Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 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 793-1221, no later than August 20, 2015. Cathy PAFoerster Chair, Commissioner �J n U STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMINT. ADVERTISING ORDER NUMBER AO-16-002 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 07/20/15 1(907) AGENCY PHONE: 793-1221 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 a a TYPE 'All It �y x LEGAL DISp1AY CLASSIFIED 07NER(Specify belotn4 '� DESCRIPTION PRICE AIO-15-032, AIO-15-033 and CO-15-09 Initials of who prepared AO: Alaska Non -Taxable 92-600185 sv$iyilT P ytil�> :sltow>Ftvc:. . R . ... :O;RDER.NO.,; CERTIFIED; AFFIDAV:fT OE;: PUBLICAiiori_WITH ATTAk;#Ep.coF:Y%)F: A3Y4E..... .NT:70::::::::::::::::::: Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pave 1 of 1 Total of All Pages $ I- .................................. REF Type Number Amount Date Comments 1 PvN ADN84501 2 Ao AO-16-002 3 4 FIN AMOUNT SY CC PGM LGR ACCT FY DIST LIQ 1 16 02140100 73451 16 z 3 4 urchasi h i T le: uthor' i nature Telephone Number 1. .0�#nd\recemng agency name must appear on all invoices and docume is relating to this purchase. 2. Theo is registered for tax free transactions under Chapter 32, IRS code. egistration number 92-73-0006 K. Items are for the exclusive use of the state and not for resale. ATSTRIBijTIONi .. ... ... . Division Fiscal/Original. A0 : Copies:: .........➢ivisioi► Fiscal, Receiving . Form:02-901 Revised: 7/20/2015 270227 • 0001368715 $ 169.34 RECEIVED JUL 3 0 2015 AFFIDAVIT OF PUBLICATION AOGCC STATE OF ALASKA THIRD JUDICIAL DISTRICT Leesa Little being first duly sworn on oath deposes and says that he/she is a representative of the Alaska Dispatch 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 July 21, 2015 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Signed 2j1-1� Subscribed and sworn to before me this 21st day of July, 2015 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES 0- �3l�lg Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO 15-032, AIO 15-033, and CO 15-09 Prudhoe Bay Unit Requested Modifications BP Exploration (Alaska) Inc., by letters dated July 17, 2015, requests the Alaska Oil and Gas Conservation Commission (AOGCC) modify Area Injection Orders 3A & 41', and conservation Order 341D authorize the injection of CO2 for enhanced recovery purposes and to increase the allowable gas offtake rate for the Prudhoe Oil Pool. The AOGCC has scheduled a public hearing on this application for August 27, 2015 at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. Written comments regarding this application may be submitted to the AOGCC, at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the August 27, 2015 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 793-1221, no later than August 20, 2015. AO-16-002 Published: July 21, 2015 Cathy P. Foerster Chair, Commissioner Notary public—�W BRIT NEY L. THOMPSON State Of Alaska MY Commission Expires Feb 23, 2019 • Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Monday, July 20, 2015 1:07 PM To: Ballantine, Tab A (LAW); 'Nathan Hile (nwhcmatrix@hotmaii.com)'; 'Salena'; glyle@guessrudd.com; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AKDCWellIntegrityCoordinator, Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; Becca Hulme; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Bruce Webb; Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Delbridge, Rena E (LAS); DNROG Units (DNR sponsored); Donna Ambruz, Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff; Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Williams, Jennifer L (LAW); Jerry Hodgden; Jerry McCutcheon; Solnick, Jessica D (LAW); Jim Watt; Jim White; Joe Lastufka; news@radiokenai.com; John Adams; Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kazeem Adegbola; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Leslie Smith; Lisa Parker, Louisiana Cutler, Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Calkins; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mkm7200; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Sternicki, Oliver R; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Terry Templeman; Thor Cutler, Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bajsarowicz, Caroline 1; Brian Gross; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Don Shaw; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Hyun, James J (DNR); Jason Bergerson; jill.a.mcleod@conocophillips.com; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kenneth Luckey, King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Matt Gill; Franger, James M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Sarah Baker, Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Todd, Richard 1 (LAW); Tostevin, Breck C (LAW); Wayne Wooster; William Hutto; William Van Dyke Subject: Public Notice (PBU Requested Modifications) AIO-15-32, AIO-15-033, CO-15-09 Attachments: Notice of Hearing, Dockets AIO-15-32, AIO-15-33, CO-15-09.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 P.O. Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Dave P. Lachance Vice President Richard Wagner Darwin Waldsmith Alaska Reservoir Development P.O. Box 60868 P.O. Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99508 Angela K. Singh Dave Lachance Vice President Alaska Reservoir Development July 17, 2015 Via Hand Delivery Cathy P. Foerster Commission Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 RECEIVED ..JUL 17 2015 AOGCC BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, AK 99508 USA Direct 907 564 4855 Mobile 907 538 1719 Main 907 564 5111 dave.lachance@bp.com Re: Consolidated Application for Amendment of Prudhoe Oil Pool Rule 9 and Modification of Prudhoe Bay Unit Area Injection Orders AIO 3A and AIO 4F Dear Chair Foerster: BP Exploration (Alaska) Inc., as an individual working interest owner (BPXA) in the Prudhoe Bay Unit (PBb), and not as PBU operator, on behalf of itself and PBU working interest owner ExxonMobil Alaska Production Inc. (EMAP), submits this consolidated application to the Alaska Oil and Gas Conservation Commission (AOGCC) to obtain two related authorizations: (i) Amendment of Rule 9 of Conservation Order (CO) 341 D for the Prudhoe Oil Pool (POP) to authorize an increase in the maximum annual average gas off - take limit from 2.7 billion standard cubic feet per day (bscf/d) to 4.1 bscf/d. (ii) Modification of AIO 3A and AIO 4F (collectively the AIOs) to authorize the injection of CO2 for enhanced recovery and pressure maintenance from sources both inside, which is already authorized, and outside the Prudhoe Bay Unit. As related procedural matters, BPXA respectfully requests that, to the full extent allowed by the applicable regulations, the AOGCC: (i) consolidate proceedings pertaining to amendment of Rule 9 and modification of the AIOs because of their interrelated nature; (ii) provide notice of a public hearing on this application tentatively scheduled for on or about August 31, 2015 in accordance with 20 AAC 25.520 and 20 AAC 25.540; (iii) tentatively schedule a pre -hearing conference for on or about August 10, 2015 in accordance with 20 AAC 25.540(f); and Application to Amend POP Mule 9 and Modify AIOs • July 17, 2015 Page - 2 (iv) allow the submission of pre -filed written testimony in support of the application pursuant to 20 AAC 25.540(c)(12) with the submitting witness(es) to be present at the public hearing to provide sworn testimony and respond to questions of the AOGCC, if any. Please note that the portion of this consolidated application contained in the Confidential Appendix is confidential, and BPXA requests that such information be held confidential pursuant to AS 31.05.035(d), 20 AAC 25.537(b), and AS 45.50.910 et seq. The Confidential Appendix is enclosed in a separate envelope and marked confidential. BPXA respectfully requests that the AOGCC make a decision on the matters addressed in this consolidated application on or before October 15, 2015. I. PRUDHOE OIL POOL RULE 9 AMENDMENT A. POP Maximum Annual Average Gas Off -Take Rate Rule 9, as adopted by the AOGCC in 1977, limits the maximum annual average gas off -take from the POP to 2.7 bscf/d. Approximately 0.6 bscf/d is currently used (and anticipated to continue to be used) for fuel, other field operations and minor local gas sales. Accordingly, under Rule 9, an annual average gas off -take of approximately 2.1 bscf/d would be available for major gas sales. BPXA and the other PBU working interest owners (individually referred to as a WIO and collectively as WIOs) and the AOGCC have long contemplated a major gas sales project involving gas from Prudhoe Bay (PBMGS). In accordance with good oil field engineering practices, at various stages of field development, the PBU WIOs have evaluated the potential effects of a PBMGS on oil production and hydrocarbon recovery from the POP based upon then - existing information and models. Gas production from the POP has been used for extraction of miscible injectant, manufacture of natural gas liquids, pressure maintenance, and enhanced oil recovery. Partly as a result of this POP gas utilization, liquid recovery from the POP has increased from the estimated 9.6 billion barrels in 1977 to over 12.2 billion barrels to date. The AOGCC held a public hearing in June 2007 and issued a report dated July 10, 2007 regarding possible amendment of Rule 9. The AOGCC concluded that no change was necessary to Rule 9 at that time.' The PBU WIOs have continued to prepare for a PBMGS and, because of progress by participants in the Alaska LNG Project (AK LNG) and related planning by the PBU ' Report of the Commission Inquiry Into Amending Rule 9 ("Pool Off -Take Rates"), CO 341 D, For the Prudhoe Oil Pool, Prudhoe Bay Field. Application to Amend POP Pe 9 and Modify AIOs • July 17, 2015 Page - 3 WIOs for a PBMGS, it is now appropriate for the AOGCC to amend Rule 9 to allow a greater gas off -take rate from the POP.2 B. Gas Off -Take for PBMGS The participants in AK LNG are progressing plans for an integrated LNG project, currently anticipated to start-up in 2025, consisting of a liquefaction facility and associated LNG storage and marine terminal facilities located in the Cook Inlet area, a large diameter gas pipeline approximately 800-miles in length (with gas off -take interconnection points to allow for in -state deliveries) connecting the liquefaction facility to a Gas Treatment Plant (GTP) on the North Slope, transmission lines between the GTP and producing fields, and various other associated facilities and infrastructure.3 On May 28, 2015 the U.S. Department of Energy conditionally granted authorization to AK LNG to export LNG to non -free trade agreement nations.4 The GTP is being designed by AK LNG to receive, treat, and ship gas to the Liquefaction Plant, and to send to the PBU a GTP by-product stream primarily consisting of carbon dioxide (CO2).5 The design of the AK LNG facilities is premised on maintaining an annual average gas supply rate of 3.5 bscf/d to the GTP .6 BPXA and EMAP plan to deliver part of the gas supply into the GTP from PBU (from the POP). C. Request to Increase POP Maximum Annual Average Off -take Rate There are several reasons why an amendment of Rule 9 to increase the maximum annual average gas off -take rate is being requested. Under expected normal operations of the GTP, approximately 75 percent of the gas supply (2.7 bscf/d) will be from the POP with approximately 25 percent of the gas (0.8 bscf/d) supplied from 2 BPXA participated in PBMGS preparations in its capacity as a PBU WIO and facilitated discussions in its capacity as PBU operator. 3 See AK LNG Preliminary Resource Report No. 1 at § 1.1, Docket No. PF 14-21-000 (doc. Number: USAKE-PT-SRREG-00-0001) (hereafter referred to as "Resource Report No. 1"), available at: https://elibLM.ferc.gov/idmws/file list.asp?document id=14300991. The AK LNG project is currently undergoing pre -filing review before the Federal Energy Regulatory Commission (FERC) at Docket No. PF14-21-000. The applicants before FERC for the AK LNG project are the Alaska Gasline Development Corporation, BP Alaska LNG LLC, ConocoPhillips Alaska LNG Company, ExxonMobil Alaska LNG LLC, and TransCanada Alaska Midstream LP. 4 See DOE/FE Order No. 3643 (FE Docket No. 14-96-LNG), available at: http: //www. energy. gov/fe/downloads/order-3 643 -alaska-ing-project-llc. 5 See Resource Report No. 1 at p.15. 6 According to the current design, the GTP will have an annual average inlet gas treating capacity of up to 3.7 bscf/d, excluding planned/unplanned downtime. Id. Assuming 95% operating efficiency, the annual average gas supply requirement for the GTP is 3.5 bscf/d. Application to Amend POP Mule 9 and Modify AIOs • July 17, 2015 Page - 4 other sources. Under normal operations, total POP gas off -take would occur at an annual average rate of approximately 3.3 bscf/d (2.7 bscf/d to the GTP plus 0.6 bscf/d for existing fuel use and minor local gas sales). The current Rule 9 off -take rate of 2.7 bscf/d is not sufficient to meet the annual average gas off -take from the POP under those circumstances. The Commission has long acknowledged that a change to the gas off -take rate from the POP would be needed to facilitate a major gas sale. In addition to POP gas supply under normal operating conditions, if the supply of gas from other sources is not delivered as expected (or during startup of, or after gas production begins to decline from, other fields), it is possible the POP would need to be the source for up to 100 percent of the gas BPXA and other parties will each need to supply to the GTP to cover gas supply commitments. In such circumstances, the total gas off -take from the POP could be up to 4.1 bscf/d (3.5 bscf/d to the GTP adjusted for the higher CO2 content of POP feed gas in comparison to the expected blended feed stream plus 0.6 bscf/d for existing fuel use and minor local sales). This application to amend Rule 9 requests an increase in the annual average off -take rate to 4.1 bscf/d to accommodate the maximum potential gas off -take from the POP in circumstances when non -POP gas supply to the GTP is not delivered as expected. D. Analysis of Increase in Gas Off -Take Upgrades to the PBU Full Field Model (FFM have been made since the AOGCC last considered POP gas off -take rates in 2007. In addition, model inputs incorporate updated production, drilling, well breakage data, and updated fuel gas algorithms. As a result of increased model resolution, other model refinements, and updated data, a greater degree of confidence in model results has been achieved regarding recovery mechanisms, well productivity, facility processing and compositional detail of oil and gas production. Analyses of the upgraded FFM were performed and presented by the PBU WIOs to AOGCC staff in workshops during April and May of this year. BPXA's assessment of the results is set forth in the Confidential Appendix to this application. BPXA believes that amendment of Rule 9 to allow a maximum annual average gas off -take rate of 4.1 bscf/d for the POP is consistent with good oilfield engineering practices, and appropriate action for the Commission to take. E. Timing for AOGCC Decision Amendment of Rule 9 is being requested at this time in consideration of current actions by the State of Alaska and the AK LNG parties, including BPXA's affiliate BP Alaska LNG LLC and EMAP's affiliate ExxonMobil Alaska LNG LLC, to progress the AK LNG project to the front- end engineering and design (FEED) development stage (which effort involves the expenditure of billions of dollars). To move to the FEED stage of project activity, a number of project -enabling 7 Resource Report No. 1 at 16, 18-19.Current GTP design contemplates that 25% of the supply into the facility will be gas delivered from the Point Thomson Unit. Application to Amend POP Mule 9 and Modify AIOs • July 17, 2015 Page - 5 actions have been identified.$ Amendment of Rule 9 to allow the flexibility to supply both ordinary and full feed gas rates to the GTP from PBU supports those activities. BPXA is requesting that the AOGCC render a decision by October 15, 2015 to facilitate those project - enabling actions. II. MODIFICATION OF AIOS A. Introduction As addressed in Sections I.A-.B above (incorporated into this request by reference), the GTP is being designed to receive, treat and ship gas to the liquefaction facility, and to return CO2 by- product to the PBU for injection. Gas will be received from multiple fields, including the POP at PBU. Similar to the requested amendment of Rule 9 addressed above, the requested modifications to the AIOs are being requested at this time to support the joint efforts of the State of Alaska and the AK LNG parties to progress the Alaska LNG Project to FEED development stage. As more specifically addressed below, modifications of the AIOs are based upon the Alaska LNG project design plan for re -injection of the GTP CO2 by-product into the POP. B. Request to Authorize Injection of CO2 1. Injection of CO2 by-product After treatment of feed gas at the GTP, the Alaska LNG Project design is to return CO2 by- product, which is greater than 99% dry CO2, to the Prudhoe Bay Unit for injection.9 BPXA's assessment is that PBMGS will enable an additional hydrocarbon recovery benefit of approximately 3.8 billion barrels of oil equivalent from the PBU, of which the injection of CO2 in the POP is a key step. BPXA's analysis and assumptions regarding CO2 injection is set forth in the Confidential Appendix to this application. Please refer to the Confidential Appendix for information provided to the Commission in support this application, pursuant to 20 AAC 25.402. 8 See Heads of Agreement for the Alaska LNG Project (Jan. 14, 2014). 9 Resource Report No. 1. Application to Amend POP Ilule 9 and Modify AIOs July 17, 2015 Page - 6 2. Modification of AIOs to authorize injection of GTP CO2 by-product will not allow or increase the risk of movement of fluids into sources of freshwater or underground drinking water Within the PBU, there are no subsurface sources of freshwater. Aquifer Exemption Order 1 states that all portions of aquifers lying directly below the Western Operating and K Pad areas of the Prudhoe Bay Unit are exempted for Class II injection activities. Based on data submitted to AOGCC, Finding 5 of AIO 4 covering the Eastern Operating Area states that "injection into, though, or above a fresh water aquifer or underground source of drinking water will not occur." The AIOs only authorize injection into an authorized injection strata. The orders contain requirements for periodic mechanical integrity testing and monitoring injection wells. Should a lack of injection zone isolation be indicated, the operator must notify the AOGCC and submit a plan of corrective action. The well must be shut-in if freshwater were threatened. As noted earlier in this Application, injection of PBU CO2 into the POP (as part of authorized PBU gas cycling operations) is already allowed by the Commission, and this request simply requests authorization for the injection of incremental CO2 from gas supplied to the GTP from other reservoirs. B. Requested modifications to AIOs BPXA requests, pursuant to 20 AAC 25.410(h), that the Commission approve the following modifications to the referenced Rule in each of the AIOs (requested modifications in bold and underlined text): 1. AREA INJECTION ORDER 3A (PRUDHOE OIL POOL) Rule 1. Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and in the strata defined as those strata which correlate with the strata found in ARCO Alaska Inc. (Atlantic -Richfield -Humble) Prudhoe Bay State Well No. 1 between the measured depths of 8110 feet and 8680 feet the following fluids may be injected for purposes of pressure maintenance and enhanced oil recovery: a) Produced water and gas from Prudhoe Bay Unit processing facilities; b) CO2 and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; Enriched hydrocarbon gas; Non -hazardous water and water based fluids - (specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); 1P Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 7 Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols; vi. Radioactive tracer survey fluids eef Non -hazardous glycols and glycol mixtures; W Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides gh Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. 2. AREA INJECTION ORDER 4F (PRUDHOE OIL POOL, PUT RIVER OIL POOL, LISBURNE OIL POOL. PT. MCINTYRE OIL POOL, WEST BEACH OIL POOL, AND STUMP ISLAND OIL POOL) Rule I Authorized Injection Strata and Fluids for Enhanced Recovery Within the affected area and the following strata: The Prudhoe Oil Pool strata defined as (i) the accumulations of oil that are common to and that correlate with the accumulations found in the Atlantic Richfield -Humble Prudhoe Bay State No. 1 well between the depths of 8,110 feet and 8,680 feet, and (ii) the accumulation of oil that is common to and correlates with the interval from 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2, dated September 28, 1975, in the Atlantic Richfield -Exxon NGI No. 1 well, and that is in hydraulic communication with the gas cap of the former accumulations in the Sag River Formation. The latter accumulation is found within the following area: Umiat Meridian. T11N R14E: Sections: 1, 2, 11(N/2 and SE/4), 12, 13, 14(E/2), 23(NE/4), 24, 25(N/2); T11N R15E: Sections: 6, 7, 8, 17, 18, 19, 20, 29(N/2), 30(N/2); T12N R14E: Sections 35, 36 The Put River Oil Pool strata are defined as the sandstone reservoirs within the Southern, Central and Western lobes of the Put River Sandstone Member (PRS) of the Kalubik Formation that correlate with the interval 9,638 to 9,719 measured feet on the Borehole Compensated Sonic Log, Run 2--dated September 28, 1975--in the Atlantic Richfield - Exxon NGI No. I well, but excluding the PRS Northern Lobe reservoirs that are in Application to Amend POP ule 9 and Modify AIOs • July 17, 2015 Page - 8 pressure communication with the Prudhoe Oil Pool gas cap in the Sag River Formation. The Put River Oil Pool is found within the following area: Umiat Meridian. T11N R14E Sections: 3, 4, 9, 10, 11(SW/4), 14(W/2), 15, 16, 21, 22, 23(W/2 and SE/4), 25(S/2), 26, 27, 28, 33, 34, 35, 36; T11N RI5E Sections: 29(S/2), 30(S/2), 31, 32; T10N R14E Sections: 1, 2, 3, 11, 12, 13, 14; T10N R15E Sections: 5, 6, 7, 8, 17, 18 The Lisburne Oil Pool strata correlate with and are common to the formations found in the ARCO Prudhoe Bay State No. 1 well between the measured depths of 8, 790-10,440. The Pt. Mcintyre Oil Pool strata correlate with and are common to the formations found in the Pt. Mcintyre No. 11 well between the measured depths of 9,908- 10,665 feet. The West Beach Oil Pool strata correlate with and are common to the formations found in the West Beach No.4 well between the measured depths of 14,458- 14,781 feet. The Stump Island Oil Pool enhanced recovery plans will be evaluated on a well - by -well basis in conjunction with Pt. Mcintyre Oil Pool development. The following fluids may be injected for pressure maintenance and enhanced recovery purposes: a) Produced water and gas from PBU processing facilities; b) CO2and other GTP effluent gases from sources within or outside the Prudhoe Bay Unit; hc) Enriched hydrocarbon gas; e4) Non -hazardous water and water based fluids -(specifically seawater, source water, freshwater, domestic wastewater, equipment washwater, sump fluids, hydrotest fluids, firewater, and water with trace chemicals, and other water based fluids with a pH greater than 2 and less than 12.5 and flashpoint greater than 140 degrees F); de) Fluids introduced to production facilities for the purpose of oil production, plant operations, plant/piping integrity or well maintenance that become entrained in the produced water stream after oil, gas, and water separation in the facility. Specifically: i. Freeze protection fluids; ii. Fluids in mixtures of oil sent for hydrocarbon recycle; iii. Corrosion/scale inhibitor fluids; iv. Anti-foams/emulsion breakers; v. Glycols Application to Amend POP Rule 9 and Modify AIOs July 17, 2015 Page - 9 efJ' Non -hazardous glycols and glycol mixtures; €g) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides gh) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. III. SUPPORTING INFORMATION This application provides comprehensive information and support for approval of the requested amendment of Rule 9 maximum annual average gas off -take rate for the POP to 4.1 bscf/d, as well as modification of the AIOs. Mr. Bruce Laughlin, as testifying witness, will be present at, and made available to, the AOGCC for questions at the public hearing with respect to this application. Depending upon the testimony, if any, presented by others at the public hearing, BPXA reserves the right to present additional testimony at the public hearing, or by post -hearing submission if so authorized by the Commission. IV. CONCLUSION Based upon this application, BPXA requests that the AOGCC: (i) amend Rule 9 of CO 341 D to establish a maximum annual average gas off -take rate of 4.1 bscf/d for the POP; and (ii) modify AIO 3A.002 and AIO 4F to authorize injection of CO2 from the PBU and other sources for the purposes of enhanced oil and gas recovery, and pressure maintenance. Please contact John Dittrich at 907-564-5075 if the Commissioners or AOGCC staff have any questions or clarification regarding this application. BPXA is represented in this matter by George Lyle of Guess & Rudd, 510 L Street, Suite 700, Anchorage, AK 99501, 907-793-2222. Please direct communications regarding procedural matters, including the pre -hearing and public hearing, to Mr. Lyle. We sincerely appreciate the time and attention of the Commissioners and the AOGCC staff to this application. Si rely, Dave P. Lachance Vice President, Reservoir Development Attachment cc: George Lyle Appendix held confidential in secure storage