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Home My WebLink AboutAIO 004 FAREA INJECTION ORDER 4F Prudhoe Bay Field Prudhoe Bay Unit Eastern Operating Area Prudhoe Oil Pool Put River Oil Pool Lisburne Oil Pool Pt. McIntyre Oil Pool West Beach Oil Pool Stump Island Oil Pool North Slope Borough, Alaska 1. September 19, 2012 BPXA's request to expand PBU Eastern Operating Area 2. September 28, 2012 Notice of public hearing, affidavit of publication, email distribution, mailings 3. October 31, 2014 BPXA's Grind and Inject Project Annual Performance 4. February 25, 2015 5. April 2, 2015 6. June 5, 2015 7. July 1, 2015 8. October 2, 2015 9. August 31, 2015 10. December 1, 2015 11. April 5, 2016 12. April 25, 2016 13. 14. 15. 16. 17. 18. September 7, 2016 October 7, 2016 September 26, 2016 Report BPXA's PSI -09 AA request (AIO 4F.001) BPXA's PBU 17-08 AA request (AIO 417.002) BPXA's PBU 04-09 AA request (AIO 4F.003) BPXA's PBU 13-06 AA request (AIO 4F.004) BPXA's PBU S -25A AA request (AIO 417.005) BPXA's email BPXA's PBU 13-17 AA request (AIO 4F.006) BPXA's PBU X-33 AA request (AIO 417.007) BPXA's PBU 14-27 AA request (AIO 4F.008) BPXA's request to amend AIO 4F.004 (BPXA withdrew request on 10/6/16) BPXA's withdrawal of September 7, 2016 request BPXA's request to amend prior orders to authorize continued GCWI into the Lisburne Oil Pool September 30, 2016 Notice of public hearing, affidavit of publication, email distribution, mailings January 26, 2017 Copy of CO 207B February 13, 2018 BPXA's request to cancel AIO 417-003 (AIO 4F-003) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska), Inc. to modify Area Injection Order 4E to accommodate expansion of the affected area. Docket Number: AIO-12-019 Area Injection Order 4F corrected Prudhoe Bay Field Prudhoe Bay Unit Eastern Operating Area Prudhoe Oil Pool Put River Oil Pool Lisburne Oil Pool Pt. McIntyre Oil Pool West Beach Oil Pool Stump Island Oil Pool North Slope Borough, Alaska July 18, 2014 IT APPEARING THAT: 1. By letter received September 25, 2012, BP Exploration (Alaska), Inc. (BPXA), requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order expanding the affected area for the Prudhoe Bay Unit (PBU) Eastern Operating Area (EOA). 2. Pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled a public hearing for November 13, 2012. On September 28, 2012, the AOGCC mailed printed copies of the notice of the opportunity for public hearing to all persons on the AOGCC's mailing distribution list, published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On October 7, 2012, the notice was published in the ALASKA JOURNAL OF COMMERCE. 3. No protest to the application or request for hearing was received. 4. The AOGCC vacated the tentatively scheduled public hearing on October 30, 2012. 5. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. FINDINGS: The AOGCC has issued numerous Area Injection Orders (AIO) and amendments to those orders to govern enhanced oil recovery injection operations in the PBU EOA. AIO 4 was issued on July 11, 1986, and amended once. AIO 4A was issued August 12, 1983, and revised once. AIO 4B was issued April 13, 1998. AIO 4C was issued March 23, 2000, corrected April 19, 2000 and amended 15 times. AIO 4D was issued December 2, 2005. AIO 4E was issued March 30, 2006, and it has been amended 42 times. Area Injection Order 4F corrected July 18, 2014 Page 2 of 7 2. BPXA is the operator of the Prudhoe Bay Field and PBU, which are located in the North Slope Borough, Alaska. 3. BPXA's proposed expansion of the affected area of AIO 4E is based on new well information and a new structural interpretation from seismic data that expands the limits of the area capable of contributing to production. 4. Regulation 20 AAC 25.460 allows the AOGCC to prescribe rules permitting the underground injection of fluids on an area basis. CONCLUSIONS: 1. BPXA's proposed expansion of the affected area of AIO 4E is warranted based on the revised structural interpretation. 2. The findings, conclusions, and administrative records for the AIOs and their amendments listed in Finding 1, above, should be combined within a single AIO to facilitate more effective administration of the PBU EOA enhanced recovery project. 3. Changes in enhanced oil recovery practices warrant periodic review and, if needed, revision of governing orders. NOW THEREFORE IT IS ORDERED: In addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), the following rules govern Class II injection operations in the affected area described below and supersede and replace the rules adopted in AIO 4E. To the extent not already incorporated into, or superseded by, these rules the administrative approvals issued under AIOs 4C and 4E remain in effect: AFFECTED AREA: (Revised this order) UMIAT MERIDIAN Township Range Section T13N R14E Section 26: S'/2 Section 27: s 1/2, NW 1/4 Protracted, All Tide and Submerged Lands Shoreward of the Line Fixed by Coordinates Found in Exhibit A of the Final decree, U.S. v. Alaska, No. 84 Original Section 28: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 312809 Section 33: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 312809 and ADL365548 Section 34: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 365548 Section 35: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548 T12N R14E Sections 3, 4, 9, 10, 13, 14, 15, 16, Section 17:NE1/4,N1/2SE1/4,E1/2E1/2NW1/4,E1/2NE1/4SW1/4, Section 21: N 1/2 NE 1/4, Sections 22, 23, 24, 25, 26, 35, and 36. Area Injection Order 4F corrected July 18, 2014 Page 3 of 7 T12N R15E Section 16: SW 1/4 Section 17: S 1/2 Sections 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T12N R16E Sections 28, 29, 30, 31, 32, 33, and Section 34: W 1/2 NW'/4, SW 1/4, and SW 1/4 SE'/4 T11N R14E Sections 1, 2, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 33, 34, 35, and 36. TIIN R15E All T11N R16E Section 2: SW 1/4 NW 1/4, SW 1/4, S 1/2 SE 1/4, Sections 3, 4, 5, 6, 7, 8, 9, 10, 11, Section 12: NW 1/4, S 1/2 NE 1/4, SE 1/4, and SW 1/4 Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 28, 29, 30, 31, 32, and 33. T10N R14E Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, and 36. T10N R15E All TION R16E Sections 4, 5, 6, 7, 8, 9, 16, 17, 18, 19, 20, 29, 30, and 31. Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK (identical with line 4-5 on block 605) and lying easterly of the west boundary of sections 2 and 11, T12N, R14E, UM, AK (identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares. Rule 1 Authorized Injection Strata and Fluids for Enhanced Recovery (Revised from AIO 4E.042) 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. I 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 Area Injection Order 4F corrected July 18, 2014 Page 4 of 7 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. 1 well, but excluding the PRS Northern Lobe reservoirs that are in 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 R15E 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) Enriched hydrocarbon gas; c) 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); d) 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 e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides Area Injection Order 417 corrected July 18, 2014 Page 5 of 7 g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. Rule 2 Authorized Injection Strata for Disposal (Source: AIO 4C) Within the affected area, Class II waste fluids may be disposed by injection into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 3,607-6,750 feet. Class II slurry injection from the Grind and Inject processes may be disposed into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 4,270-6,750 feet. Rule 3 Fluid Injection Wells (Source: AIO 4C) The injection of fluids must be conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AI04D) The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for AOGCC inspection. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Revoked: AI04D) Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AI04E) 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. A 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/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. Area Injection Order 4F corrected July 18, 2014 Page 6 of 7 Rule 7 Well Integrity Failure (Source: AI04E) 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 injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Injection Wells (Source: AIO 4C) An injection well located within the affected area must not be plugged or abandoned unless approved by the AOGCC in accordance with 20 AAC 25.105. Rule 9 Administrative Action (Source: AIO 4D) Unless notice and public hearing are otherwise required, the AOGCC may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. Rule 10 Surveillance (Source: AIO 4C and AIO 4C.001) For slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the AOGCC. Operating parameters including disposal rate, disposal pressure, annulus pressures and volume of slurry pumped must be monitored and reported according to the requirements of 20 AAC 25.432. Also for slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Reports shall cover the time period of October 1st through September 30th and submission must be on or before November 15th Rule 11 Notification (Source: AIO 4C) The operator must notify the AOGCC if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. Area Injection Order 4F corrected July 18, 2014 Page 7 of 7 This order shall expire 5 years after the effective date shown below. DONE at Anchorage, Alaska and dated July 18, 2014. �0 Lq�yo Cathy P. Foerster Daniel T. eamount, Jr. Chair, Commissioner Commissioner noa 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 n.m. on the next day that does not fall on a weekend or state holiday. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, July 18, 2014 3:29 PM To: (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker, Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey; Colleen Miller, Corey Cruse; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; 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 P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette, Scott Griffith; Shannon Donnelly, Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonee D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Diane Richmond; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; 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); Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Wendy Wollf, 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); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (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 To: (DOA); Wallace, Chris D (DOA) Subject: Area Injection Order 4F Errata Notice and Corrected (Prudhoe Bay Field) Attachments: aio4f corrected.pdf; aio4f errata notice.pdf Please see attached. Samartata CarCisCe Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (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.Carlisle@alaska.gov. Jerry Hodgden Penny Vadla George Vaught, Jr. Hodgden Oil Company 399 W. Riverview Ave. Post Office Box 13557 40818' St. Soldotna, AK 99669-7714 Denver, CO 80201-3557 Golden, CO 80401-2433 CIRI North Slope Borough Bernie Karl K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Past Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson lack Hakkila Post Office Box 190083 Post Office Box 60868 3201 Westmar Cir. Anchorage, AK 99508-4336 Anchorage, AK 99519 Fairbanks, AK 99706 Katrina Cooper Darwin Waldsmith James Gibbs Manager Base Management BP Exploration (Alaska), Inc. Post Office Box 39309 Post Office Box 1597 Post Office Box 196612 Ninilchik, AK 99639 Soldotna, AK 99669 Anchorage, AK 99519-6612 Angela K. Singh STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska), Inc. to modify Area Injection Order 4E to accommodate expansion of the affected area. Docket Number: AIO-12-019 Area Injection Order 4F Prudhoe Bay Field Prudhoe Bay Unit Eastern Operating Area Prudhoe Oil Pool Put River Oil Pool Lisburne Oil Pool Pt. McIntyre Oil Pool West Beach Oil Pool Stump Island Oil Pool North Slope Borough, Alaska July 18, 2014 ERRATA NOTICE The Alaska Oil and Gas Conservation Commission (AOGCC) notes that the change in due date for slurry injection operation reporting requirements that were approved in Area Injection Order (AIO) 4C.001 were inadvertently not included in the recently issued AIO 4F. Rule 10 Surveillance will be corrected to incorporate the proper due date and a corrected Area Injection Order 4F will be issued by the AOGCC. DONE at Anchorage, Alaska and dated July 18, 2014 Cathy . Foerster Chair, Commissioner r. 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. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, July 18, 2014 3:29 PM To: (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew Vanderlack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey, Colleen Miller, Corey Cruse; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David Goade; David House; David McCaleb; David Scott; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff; Jacki Rose; Jdarlington oarlington@gmaii.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; 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 P. Worcester, Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover; Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer, Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater; Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Diane Richmond; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; 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); Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Wendy Wollf, 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); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, lames B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K To: (DOA); Wallace, Chris D (DOA) Subject: Area Injection Order 4F Errata Notice and Corrected (Prudhoe Bay Field) Attachments: aio4f corrected.pdf; aio4f errata notice.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 71h Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (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.Carlisle@alaska.gov. Jerry Hodgden Penny Vadla George Vaught, Jr. Hodgden Oil Company 399 W. Riverview Ave. Post Office Box 13557 408 le St. Soldotna, AK 99669-7714 Denver, CO 80201-3557 Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. Land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 190093 Post Office Box 60868 3201 Westmar Cir. Anchorage, AK 99508-4336 Anchorage, AK 99519 Fairbanks, AK 99706 Katrina Cooper Darwin Waldsmith James Gibbs Manager Base Management Post Office Box 39309 Post Office Box 1597 BP Exploration (Alaska), Inc. Ninilchik, AK 99639 Soldotna, AK 99669 Post Office Box 196612 Anchorage, AK 99519-6612 ��(L Angela K. Singh STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska), Inc. to modify Area Injection Order 4E to accommodate expansion of the affected area. Docket Number: AIO-12-019 Area Injection Order 4F Prudhoe Bay Field Prudhoe Bay Unit Eastern Operating Area Prudhoe Oil Pool Put River Oil Pool Lisburne Oil Pool Pt. McIntyre Oil Pool West Beach Oil Pool Stump Island Oil Pool North Slope Borough, Alaska July 17, 2014 IT APPEARING THAT: 1. By letter received September 25, 2012, BP Exploration (Alaska), Inc. (BPXA), requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order expanding the affected area for the Prudhoe Bay Unit (PBU) Eastern Operating Area (EOA). 2. Pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled a public hearing for November 13, 2012. On September 28, 2012, the AOGCC mailed printed copies of the notice of the opportunity for public hearing to all persons on the AOGCC's mailing distribution list, published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On October 7, 2012, the notice was published in the ALASKA JOURNAL OF COMMERCE. 3. No protest to the application or request for hearing was received. 4. The AOGCC vacated the tentatively scheduled public hearing on October 30, 2012. 5. Because BPXA provided sufficient information upon which to make an informed decision, the request can be resolved without a hearing. FINDINGS: The AOGCC has issued numerous Area Injection Orders (AIO) and amendments to those orders to govern enhanced oil recovery injection operations in the PBU EOA. AIO 4 was issued on July 11, 1986, and amended once. AIO 4A was issued August 12, 1983, and revised once. AIO 4B was issued April 13, 1998. AIO 4C was issued March 23, 2000, corrected April 19, 2000 and amended 15 times. AIO 4D was issued December 2, 2005. AIO 4E was issued March 30, 2006, and it has been amended 42 times. Area Injection Order 4F July 17, 2014 Page 2 of 7 2. BPXA is the operator of the Prudhoe Bay Field and PBU, which are located in the North Slope Borough, Alaska. 3. BPXA's proposed expansion of the affected area of AIO 4E is based on new well information and a new structural interpretation from seismic data that expands the limits of the area capable of contributing to production. 4. Regulation 20 AAC 25.460 allows the AOGCC to prescribe rules permitting the underground injection of fluids on an area basis. CONCLUSIONS: 1. BPXA's proposed expansion of the affected area of AIO 4E is warranted based on the revised structural interpretation. 2. The findings, conclusions, and administrative records for the AIOs and their amendments listed in Finding 1, above, should be combined within a single AIO to facilitate more effective administration of the PBU EOA enhanced recovery project. 3. Changes in enhanced oil recovery practices warrant periodic review and, if needed, revision of governing orders. NOW THEREFORE IT IS ORDERED: In addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), the following rules govern Class II injection operations in the affected area described below and supersede and replace the rules adopted in AIO 4E. To the extent not already incorporated into, or superseded by, these rules the administrative approvals issued under AIOs 4C and 4E remain in effect: AFFECTED AREA: (Revised this order) UMIAT MERIDIAN Township Range Section T13N R14E Section 26: S 1/2 Section 27: s 1/z, NW 1/4 Protracted, All Tide and Submerged Lands Shoreward of the Line Fixed by Coordinates Found in Exhibit A of the Final decree, U.S. v. Alaska, No. 84 Original Section 28: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 312809 Section 33: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 312809 and ADL365548 Section 34: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL 365548 Section 35: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548 T12N R14E Sections 3, 4, 9, 10, 13, 14, 15, 16, Section 17:NE1/4,N1/2SE1/4,E1/2E1/2NW1/4,E1/2NE1/4SW1/4, Section 21: N 1/2 NE 1/4, Sections 22, 23, 24, 25, 26, 35, and 36. Area Injection Order 4F July 17, 2014 Page 3 of 7 T12N R15E Section 16: SW 1/4 Section 17: S 1/2 Sections 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T12N R16E Sections 28, 29, 30, 31, 32, 33, and Section 34: W 1/2 NW 1/4, SW 1/4, and SW 1/4 SE 1/4 T11N R14E Sections 1, 2, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 33, 34, 35, and 36. T11N R15E All T11N R16E Section 2: SW 1/4 NW 1/4, SW 1/4, S 1/2 SE 1/4, Sections 3, 4, 5, 6, 7, 8, 9, 10, 11, Section 12: NW 1/4, S 1/2 NE 1/4, SE 1/4, and SW 1/4 Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 28, 29, 30, 31, 32, and 33. T10N R14E Sections 1, 2, 3, 4, 9, 10, 11, 12, 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, and 36. T10N R15E All T10N R16E Sections 4, 5, 6, 7, 8, 9, 16, 17, 18, 19, 20, 29, 30, and 31. Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK (identical with line 4-5 on block 605) and lying easterly of the west boundary of sections 2 and 11, T12N, R14E, UM, AK (identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram," approved 12/9/79, containing 1457.32 hectares. Rule 1 Authorized Injection Strata and Fluids for Enhanced Recovery (Revised from AIO 4E.042) 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 Area Injection Order 4F July 17, 2014 Page 4 of 7 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. 1 well, but excluding the PRS Northern Lobe reservoirs that are in 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; TUN R15E 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) Enriched hydrocarbon gas; c) 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); d) 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 e) Non -hazardous glycols and glycol mixtures; f) Fluids that are used for their intended purpose within the oil production process. Specifically: i. Scavengers; ii. Biocides Area Injection Order 4F July 17, 2014 Page 5 of 7 g) Fluids to monitor or enhance reservoir performance. Specifically: i. Tracer survey fluids; ii. Well stimulation fluids; iii. Reservoir profile modification fluids. Rule 2 Authorized Injection Strata for Disposal (Source: AIO 4C) Within the affected area, Class II waste fluids may be disposed by injection into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 3,607-6,750 feet. Class II slurry injection from the Grind and Inject processes may be disposed into strata defined as those which correlate with and are common to the strata found in the ARCO Sag River State No. 1 well between the measured depths of 4,270-6,750 feet. Rule 3 Fluid Injection Wells (Source: AIO 4C) The injection of fluids must be conducted: 1) through a new well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005; 2) through an existing well that has been approved for conversion to a service well for injection in conformance with 20 AAC 25.280; or 3) through a well that existed as a service well for injection purposes on the date of this order. Rule 4 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AI04D) The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by extreme weather condition, emergency situations, or similar unavoidable circumstances. Monitoring results shall be documented and made available for AOGCC inspection. Rule 5 Reporting the Tubing -Casing Annulus Pressure Variations (Revoked: AI04D) Rule 6 Demonstration of Tubing/Casing Annulus Mechanical Integrity (Source: AI04E) 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. A 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/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: AI04E) 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 Area Injection Order 4F July 17, 2014 Page 6 of 7 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 injection rates must be provided to the AOGCC for all injection wells indicating well integrity failure or lack of injection zone isolation. Rule 8 Plugging and Abandonment of Injection Wells (Source: AIO 4C) An injection well located within the affected area must not be plugged or abandoned unless approved by the AOGCC in accordance with 20 AAC 25.105. Rule 9 Administrative Action (Source: AIO 4D) Unless notice and public hearing are otherwise required, the AOGCC may administratively waive or amend any rule stated above 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 fluid movement outside of the authorized injection zone. Rule 10 Surveillance (Source: AIO 4C) For slurry injection wells, a baseline temperature survey from surface to total depth, initial step rate test to pressures equal or exceeding maximum injection pressure and pressure falloff are required prior to sustained disposal injection. Regular fill depth tags are required at least once annually or as warranted following consultation with the AOGCC. Operating parameters including disposal rate, disposal pressure, annulus pressures and volume of slurry pumped must be monitored and reported according to the requirements of 20 AAC 25.432. Also for slurry injection wells, an annual performance report will be required including rate and pressure performance, surveillance logging, fill depth, survey results, and volumetric analysis of the disposal storage volume, estimate of fracture growth, if any, and updates of operational plans. Report submission must be on or before July 1. Rule 11 Notification (Source: AIO 4C) The operator must notify the AOGCC if it learns of any improper Class II injection. Additionally, notification requirements of any other State or Federal agency remain the operators' responsibility. Area Injection Order 4F July 17, 2014 Page 7 of 7 This order shall expire 5 years after the effective date shown below. DONE at Anchorage, Alaska and dated July 17, 2014. Cathy . Foerster Daniel T. Seamo t, Jr. Chair, Commissioner Commissione 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. Singh, Angela K (DOA) From: Carlisle, Samantha 1 (DOA) Sent: Thursday, July 17, 2014 3:11 PM To: (michael j.nelson@conocophillips.com); AKDCWellIntegrityCoordinator, Alexander Bridge; Andrew Vandedack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Barron, William C (DNR); Bill Penrose; Bill Walker; Bob Shavelson; Brian Havelock; Burdick, John D (DNR); Cliff Posey, Colleen Miller, Corey Cruse; Crandall, Krissell; D Lawrence; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy, David Goade; David House; David McCaleb; David Scott; David Steingreaber, David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallegos; Donna Ambruz; Dowdy, Alicia G (DNR); Dudley Platt; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer; Frank Molli; Gary Schultz (gary.schultz@alaska.gov); George Pollock; ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; gspfoff, Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jones, Jeffery B (DOA); Jerry McCutcheon; Jim White; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; Jon Goltz; Jones, Jeffrey L (GOV); Juanita Lovett; Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Keith Wiles; Kelly Sperback; Klippmann; 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 P. Worcester; Mark Wedman; Kremer, Marguerite C (DNR); Michael Jacobs; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (DNR); knelson@petroleumnews.com; Nick W. Glover, Nikki Martin; NSK Problem Well Supv; Oliver Sternicki; Patty Alfaro; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Randy L. Skillern; Randy Redmond; Rena Delbridge; Renan Yanish; Robert Brelsford; Ryan Tunseth; Sandra Haggard; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Sondra Stewman; Stephanie Klemmer; Steve Kiorpes; Moothart, Steve R (DNR); Suzanne Gibson; sheffield@aoga.org; Tania Ramos; Ted Kramer; Davidson, Temple (DNR); Terence Dalton; Teresa Imm; Thor Cutler, Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger, trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; David Lenig; Diane Richmond; Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr, Smith, Graham O (PCO); Greg Mattson; Hans Schlegel; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; 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); Peter Contreras; Richard Garrard; Richard Nehring; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, Wendy Wollf, 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); Ferguson, Victoria L (DOA); Foerster, Catherine P (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (DOA); Jackson, Jasper C (DOA); Kair, Michael N (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 To: (DOA); Wallace, Chris D (DOA) Subject: Area Injection Order 4F (Prudhoe Bay Field) Attachments: aio4f.pdf Please see attached. Samantha. CarCisCe Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDEN77ALITYNOTICE. 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.Carlisle@alaska.gov. Penny Vadla George Vaught, Jr. Jerry Hodgden 399 W. Riverview Ave. Post Office Box 13557 Hodgden Oil Company Soldotna, AK 99669-7714 Denver, CO 80201-3557 40818 St. Golden, CO 80401-2433 Bernie Karl CIRI North Slope Borough K&K Recycling Inc. land Department Planning Department Post Office Box 58055 Post Office Box 93330 Post Office Box 69 Fairbanks, AK 99711 Anchorage, AK 99503 Barrow, AK 99723 Richard Wagner Gordon Severson Jack Hakkila Post Office Box 60868 3201 Westmar Cir. Post Office Box 190083 Fairbanks, AK 99706 Anchorage, AK 99508-4336 Anchorage, AK 99519 Katrina Cooper Darwin Waldsmith James Gibbs Manager Base Management Post Office Box 39309 Post Office Box 1597 BP Exploration (Alaska), Inc. Ninilchik, AK 99639 Soldotna, AK 99669 Post Office Box 196612 Anchorage, AK 99519-6612 TA9�� Angela K. Singh THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.001 Mr. Douglas A. Cismoski Well 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.alaska.gov Re: Docket Number: AIO-15-012 Request for administrative approval to allow well PSI-09 (PTD 2021240) to be online in water only injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) PSI-09 (PTD 2021240) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated February 25, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 04F.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 in December 2014. BPXA performed diagnostics and completed a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 8, 2014 which indicates that PSI-09 exhibits at least two competent barriers to the release of well pressure. BPXA also performed a passing non -state witnessed Mechanical Integrity Test of the Tubing (MIT-T) on February 19, 2015 which confirmed tubing integrity. The well has a recorded IA build up rate of 158 psi/day. 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 4F.001 March 6, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in PBU PSI-09 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; 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 8, 2014. DONE at Anchorage, Alaska and dated March 6, 2015. Cathy . Foerster Daniel T. Seamourff, Jr. Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE Michael Gallaghe 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. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Friday, March 06, 2015 3:54 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia 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); Gallagher, Mike (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (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); AKDCWeIIIntegrityCoordinator, Alexander Bridge; Allen Huckabay; Andrew VanderJack; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bill Walker, Bob Shavelson; Brian Havelock, Burdick, John D (DNR); Carrie Wong; Cliff Posey, Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David Goade; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallego; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, 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, 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 Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mjnelson; mkm7200; Morones, Mark P (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; Thor Cutler, Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Dickenson, Hak K (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; Jason Bergerson; Jennifer Starck; 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; Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; Todd, Richard J (LAW); Tostevin, Breck C (LAW); Wayne Wooster, William Hutto; William Van Dyke Subject: AIO 4F.001(Prudhoe Bay Unit) Attachments: aio4f-001.pdf Please see attached. Samantha Carlisle Executive Secretary I1 Alaska Oil and Gas Conservation Commission 333 West 701 Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (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.Carlisle@alaska.gov. James Gibbs Jack Hakkila Bernie Karl Post Office Box 1597 Post Office Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 Post Office Box 58055 Fairbanks, AK 99711 Gordon Severson Penny Vadla George Vaught, Jr. 3201 Westmar Cir. 399 W. Riverview Ave. Post Office Box 13557 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Mr. Douglas A. Cismoski Richard Wagner Darwin Waldsmith Well Intervention Manager Post Office Box 60868 Post Office Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 Ww2:(-6L vo'& CA' 'r 201L`s 01-�Scs-� Angela K. Singh THE STATE 0LiLC1S1\L-1 GOVERNOR BILL WALKER Mr. Ryan Daniel Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4F.002 Alaska Wells Integrity and Compliance Team Lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-15-014 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaskc.gov Request for administrative approval to allow well 17-08 (PTD 1810740) to be online in water only injection service with known well integrity issues. Prudhoe Bay Unit (PBU) 17-08 (PTD 1810740) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Daniel: By letter dated April 2, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 04F.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 production casing leak at 540 feet to AOGCC in March 2014. BPXA performed diagnostics and performed a tubing punch (8294 feet to 8296 feet) and cement squeeze of the inner annulus under Sundry 314-477 in January 2015. The cement top was estimated at 4679 feet, with the upper water injection perforation located at 8985 feet. BPXA performed a passing waterflow log on March 27, 2015 which indicates no upward movement of fluid in the IA across the cemented interval. BPXA completed a passing state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on March 31, 2015 which indicates that 17-08 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 4F.002 April 3, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 17-08 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 perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2000 psi; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is March 31, 2015. DONE at Anchorage, Alaska and dated April 3, 2015. 1-15 Cathy/P. Foerster Y5aiIiel T. Seamount, Jr. Chair, Commissioner Commissioner 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. Singh, Angela K (DOA) From: Carlisle, Samantha J (DOA) Sent: Monday, April 06, 2015 9:30 AM To: AKDCWellIntegrityCoordinator, Alexander Bridge; Allen Huckabay; Andrew VanderJack, Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Bob Shavelson; Brian Havelock, Burdick, John D (DNR); Carrie Wong; Cliff Posey; Colleen Miller, Crandall, Krissell; D Lawrence; Dave Harbour, David Boelens; David Duffy; David Goade; David House; David McCaleb; David Steingreaber; David Tetta; Davide Simeone; ddonkel@cfl.rr.com; Dean Gallego; Delbridge, Rena E (LAS); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Francis S. Sommer, 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, 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. han ley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mary Cocklan-Vendl; Michael Duncan; Michael Moora; Mike Bill; mike@kbbi.org; Mikel Schultz; MJ Loveland; mjnelson; 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; Thor Cutler; Tim Mayers; Todd Durkee; Tony Hopfinger; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Walter Featherly; yjrosen@ak.net; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andrew Cater, Anne Hillman; Bruce Williams; Bruno, Jeff J (DNR); Caroline Bajsarowicz; Casey Sullivan; Diane Richmond; Dickenson, Hak K (DNR); Donna Vukich; Eric Lidji; Erik Opstad; Gary Orr; Smith, Graham O (PCO); Greg Mattson; Heusser, Heather A (DNR); Holly Pearen; James Rodgers; 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; Matt Gill; Franger, lames M (DNR); Morgan, Kirk A (DNR); Pat Galvin; Bettis, Patricia K (DOA); Peter Contreras; Richard Garrard; Robert Province; Ryan Daniel; Sandra Lemke; Pexton, Scott R (DNR); Peterson, Shaun (DNR); Pollard, Susan R (LAW); Talib Syed; Terence Dalton; 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); Gallagher, Mike (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Hunt, Jennifer L (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: AIO 4F.002 (Prudhoe Bay Unit) Attachments: aio4f-002.pdf Please see attached. Samantha Carlisle Executive Secretary II Alaska Oil and Gas Conservation Commission 333 West Th Avenue Anchorage, AK 99501 (907) 793-1223 (phone) (907) 276-7542 (fax) CONFIDENTTALITYNOTICE: 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.Carlisle@alaska.gov. James Gibbs Jack Hakkila Bernie Karl Post Office Box 1597 Post Office Box 190083 K&K Recycling Inc. Soldotna, AK 99669 Anchorage, AK 99519 Post Office 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. Post Office Box 13557 Denver, CO 80201-3557 Mr. Ryan Daniel Richard Wagner Darwin Waldsmith Alaska Wells Integrity and Compliance Team Lead Post Office Box 60868 Post Office Box 39309 BP Exploration (Alaska), Inc. Fairbanks, AK 99706 Ninilchik, AK 99639 P.O. Box 196612 Anchorage, AK 99519-6612 =� �l'kk 20 l5 Angela K. Singh. THE STATE °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.claska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.003 CANCELLATION Mr. Oliver Sternicki Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AlO- 18 -022 Request to cancel Area Injection Order (AIO) 417.003 Prudhoe Bay Unit (PBU) 04-09 (PTD 1760300) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Stemicki: By letter dated February 13, 2018, BP Exploration (Alaska), Inc. (BPXA) requested cancellation of administrative approval (AA) Area Injection Order 4F.003. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request to cancel the AA. PBU 04-09 developed an inner annulus by outer annulus communication and on June 29, 2015 the AOGCC issued AIO 417.003. AOGCC determined that water injection could safely continue if BPXA complied with the restrictive conditions set out in AA AIO 4F.003. BPXA has recently converted the well from an injector to a producer via Sundry 317-601. AA AIO 4F.003 is no longer necessary to the operation of 04-09 and is hereby CANCELLED. DONE at Anchorage, Alaska and dated May 21, 2018. Hollis S. French Chair, Commissioner P - Cathy/P. Foerster Commissioner AIC) 4F.003 Cancellation May 21, 2018 Page 2 of 2 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 aweekend or state holiday. THE STATE °1ALASKA GOVERNOR BILL WALKFR Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 oogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.003 CANCELLATION Mr. Oliver Stemicki Well Integrity Engineer BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-18-022 Request to cancel Area Injection Order (AIO) 417.003 Prudhoe Bay Unit (PBU) 04-09 (PTD 1760300) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Stemicki: By letter dated February 13, 2018, BP Exploration (Alaska), Inc. (BPXA) requested cancellation of administrative approval (AA) Area Injection Order 4F.003. In accordance with Rule 9 of Area Injection Order (AIO) 4G.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS BPXA's request to cancel the AA. PBU 04-09 developed an inner annulus by outer annulus communication and on June 29, 2015 the AOGCC issued AIO 4F.003. AOGCC determined that water injection could safely continue if BPXA complied with the restrictive conditions set out in AA AIO 4F.003. BPXA has recently converted the well from an injector to a producer via Sundry 317-601. AA AIO 417.003 is no longer necessary to the operation of 04-09 and is hereby CANCELLED. DONE at Anchorage, Alaska and dated May 21, 2018. //signature on file// Hollis S. French Chair, Commissioner //signature on file// Cathy P. Foerster Commissioner AIO 4F.003 Cancellation May 21, 2018 Page 2 of 2 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 ordefsult after which the designated period begins to run isnot 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 nuns until 5:00 p.m. on the next day that does not fall on a weekend mr state holiday. From: Colombie, Jody J (DOA) Sent: Monday, May 21, 2018 2:35 PM To: Ballantine, Tab A (LAW); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody 1 (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Earl, Adam G (DOA); Erickson, Tamara K (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Laubenstein, Lou (DOA); Loepp, Victoria T (DOA); McLeod, Austin (DOA); Mcphee, Megan S (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Rixse, Melvin G (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Wallace, Chris D (DOA); Ballantine, Tab A (LAW); AK, GWO Projects Well Integrity, AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter, Allen Huckabay; Andrew Vanderlack, 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; David Pascal; 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 (LDZJn; 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 oim4thgn@gmail.com); 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 J (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; 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 Tirpack; 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; Stephen Ratcliff; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Tim Mayers; Todd Durkee; Tom Maloney, Tyler Senden; Umekwe, Maduabuchi P (DNR); Vern Johnson; 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, 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; Marie Steele; Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Patricia Bettis; 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: AIO 2C.059 and AIO 4F.003 Cancellation Attachments: aio2c.059.pdf; aio4F.003 cancellation.pdf Please see attached: Docket Number: AIO-18-023 Request for administrative approval to allow well 1 F-02 (PTD 1822110) to be online in water only injection service with a known inner annulus (IA) by outer annulus (OA) communication. Kuparuk River Unit (KRU) 1 F-02 (PTD 1822110) Kuparuk River Field Kuparuk River Oil Pool Docket Number: AIO-18-022 Request to cancel Area Injection Order (AIO) 417.003 Prudhoe Bay Unit (PBU) 04-09 (PTD 1760300) Prudhoe Bay Field Prudhoe Oil Pool Jody J. Cotombie .AOGCC Specia(AAssistant .Alaska OilandGas Conservation Commission 333 West /i17 .Avenue -Anchorage, .Alaska 99501 Office: (907) 793-1221 -Tax: (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 reciptent(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. 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 °fALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.003 Mr. Douglas A. Cismoski Well 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.alaska.gov Re: Docket Number: AIO-15-025 Request for administrative approval to allow well 04-09 (PTD 1760300) to be online in water only injection service with known inner annulus by outer annulus communication. Prudhoe Bay Unit (PBU) 04-09 (PTD 1760300) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated June 5, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 04F.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 received approval from AOGCC to bring 04-09 under evaluation in July 2014 after the well had been shut in since November 12, 2012 due to a reported potential Inner Annulus (IA) x Outer Annulus (OA) pressure communication. BPXA has completed diagnostic testing but during the approved monitoring period the OA continued to demonstrate a slow rise in pressure. AOGCC finds that BPXA is able to manage the pressure with periodic pressure bleeds. The passing non -state witnessed mechanical integrity tests of the Inner Annulus (MITIA) on August 13, 2014 and Outer Annulus (MITOA) on August 12, 2014 indicates that 04-09 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 4F.003 June 29, 2015 Page 2 of 2 AOGCC's approval to continue water injection only in PBU 04-09 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 immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 5. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 6. 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. The Commission 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 June 29, 2015. X / 9�r�-4z"— -e?� — Cathy Y. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner 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. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Monday, June 29, 2015 3:52 PM To: 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); 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; 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); Donna Ambruz; Ed Jones; Elowe, Kristin; Evans, John R (LDZX); Frank Molli; Gary Oskolkosf, George Pollock; ghammons; Gordon Pospisil; Greg Duggin; Gregg Nady; gspfoff, Hulme, Rebecca E (DNR); 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; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; 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 Subject: aio4f-003 BPXA (PBU 04-09) Attachments: aio4f-003.pdf James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. 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 Mr. Douglas A. Cismoski Richard Wagner Darwin Waldsmith Well 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 Angela K. Singh THE STATE Alaska Oil and Gas ofAT AS A Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 ADMINISTRATIVE APPROVAL www.aogcc.alaska.gov AREA INJECTION ORDER NO.4F.004 Mr. Clint J. Spence Well Intervention ETL BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-15-030 Request for administrative approval to allow well 13-06A (PTD 1972180) to be online in water only injection service with a shallow packer depth. Prudhoe Bay Unit (PBU) 13-06A (PTD 1972180) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Spence: By letter dated July 1, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 04F.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 determined that 13-06 has a production casing leak at 238 ft which will be repaired per Sundry 315-264. The repair is a cement squeeze of the inner annulus with the top of cement estimated to be 1600 ft. BPXA plans to then cement the outer annulus entirely to surface. However, since the inner annulus will be cemented leaving only approximately 1600 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. Pending the successful sundry 315-264 operations, BPXA will test the tubing and the 1600 ft of inner annulus prior to placing the well back into water only service. Upon passing the mechanical integrity tests, AOGCC can find that 13-06A exhibits at least two competent barriers AIO 417.004 July 9, 2015 Page 2 of 2 to the release of well pressure and determine 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 water injection only in PBU 13-06A is conditioned upon the following: 1. BPXA shall run an initial cement evaluation log as per Sundry 315-264 to confirm inner annulus isolation across the cemented interval and to determine the top of cement. 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. 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 perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the inner annulus pressure to below 2000 psi. 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. 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 July 9, 2015.X12 �J'`' ;� j 1"►2 I(/ v Cathy . Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioners?, ' 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. Singh, Angela K (DOA) From: Colombie, Jody J (DOA) Sent: Friday, July 10, 2015 9:08 AM To: 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); 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); 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; Greg Duggin; Gregg Nady; gspfoff; Hulme, Rebecca E (DNR); 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; 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 Subject: aio4f-004 (PBU 13-06A) Attachments: aio4f-004.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. Clint J. Spence Richard Wagner Darwin Waldsmith Well Intervention ETL 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 o'z;�Q& \O, 20\� Angela K. Singh THE STATE 0'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.005 Mr. Douglas A. Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-15-044 333 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-25A (PTD 1982140) to be online in water only injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) S-25A (PTD 1982140) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated September 10, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4F.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 12, 2015 which indicates that S-25A exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 101 psi/day and 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. AOGCC's approval to continue water injection only in PBU S-25A 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 2500 psi; 5. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; AIO 4F.005 October 2, 2015 Page 2 of 2 0 7. 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 is May 12, 2015. DONE at Anchorage, Alaska and dated October 2, 2015. Cathy P. Foerster Chair, Commissioner aniel T. Seamount, Jr. Commissioner 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 fire 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: Thursday, October 01, 2015 3:04 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); 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); AKDCWellIntegrityCoordinator; 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; 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; 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; 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; 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 Subject: aio4f-005 (BPXA) PBU Attachments: aio4f-005.pdf Jody J. Cotombie .AOGCC Specia(Assistant .ACaska Oil and Gas Conservation Commission 333 West 7`' .Avenue .Anchorage, .ACaska 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 iody.colombie@alaska.gov. James Gibbs Jack Hakkila Bernie Karl P.O. Box 1597 P.O. Box 190083 K&K Recycling Inc. 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 Mr. Douglas A. Cismoski Richard Wagner Darwin Waldsmith Well 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 Angela K. Singh THE STATE o/ALAJKC1 GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.006 Mr. Douglas A. Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-15-052 333 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 13-17 (PTD 1820260) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) 13-17 (PTD 1820260) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated December 1, 2015, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4F.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 a potential production casing leak at 9467 ft to AOGCC in 2011 and the well was shut in. BPXA performed diagnostics and performed a tubing punch (10070 ft to 10075ft and 10218 ft to 10220 ft) and cement squeeze of the inner annulus under Sundry 315-108 in June 2015. The cement top was estimated at 3220 ft, with the upper injection perforation located at 11054 ft. BPXA performed a passing waterflow log on November 30, 2015 which indicates no upward movement of fluid in the IA across the cemented interval. However, since the inner annulus is cemented leaving only approximately 3200 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. AIO 4F.006 December 7, 2015 Page 2 of 2 BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Tubing (MITT) on August 19, 2015 and a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 3, 2015 which indicates that 13-17 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. AOGCC's approval to continue WAG injection in PBU 13-17 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 perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2000 psi; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. The MIT anniversary date is October 3, 2015. DONE at Anchorage, Alaska and dated December 7, 2015. thy . F rster Daniel T. Seamount, Jr. air, ommissioner Commissioner 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. Radler, 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 tie 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: Monday, December 07, 2015 2:07 PM To: '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; David Tetta; Don Shaw; 'Donna Vukich'; Eric Lidji; 'Gary Orr'; 'Graham Smith'; Hak Dickenson; Heusser, Heather A (DNR); Holly Pearen; James Hyun; 'Jason Bergerson'; 'Jim Magill'; Joe Longo; John Martineck, Josh Kindred; Kenneth Luckey; King, Kathleen J (DNR); Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); 'Louisiana Cutler'; Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; 'Patricia Bettis'; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; Sarah Baker; Shaun Peterson; 'Susan Pollard'; Talib Syed; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); 'Wayne Wooster'; 'William Van Dyke'; 'AKDCWellIntegrityCoordinator'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Caleb Conrad'; 'Carrie Wong'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; 'David Steingreaber'; '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'; 'Gordon Pospisil'; 'Gregg Nady'; 'gspfoff'; Hyun, James J (DNR); 'Jacki Rose'; 'Jdarlington Oarlington@gmail.com)'; 'Jeanne McPherren'; 'Jennifer Williams'; 'Jerry Hodgden'; 'Jerry McCutcheon'; 'Jessica Solnick'; 'Jim Watt'; 'Jim White'; 'Joe Lastufka'; 'Joe Nicks'; 'John Adams'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karl Moriarty'; 'Kazeem Adegbola'; 'Keith Wiles'; 'Kelly Sperback'; 'Laura Silliphant (laura.gregersen@alaska.gov)'; 'Leslie Smith'; 'Lisa Parker'; 'Luke Keller'; 'Marc Kovak'; 'Mark Dalton'; 'Mark Hanley (mark.hanley@anadarko.com)'; 'Mark Landt'; 'Mark Wedman'; 'Marquerite kremer (meg.kremer@alaska.gov)'; 'Mary Cocklan-Vendl'; 'Michael Calkins'; 'Michael Duncan'; 'Michael Moora'; 'Mike Bill'; 'Mike Mason'; 'Mike) Schultz'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; '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; '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; 'Stephan Hennigan'; 'Stephanie Klemmer'; Sternicki, Oliver R; Steve Moothart (steve.moothart@alaska.gov); 'Suzanne Gibson'; Tamera Sheffield; 'Tanis Ramos'; 'Ted Kramer'; Temple Davidson; Teresa Imm; Thor Cutler, 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano; 'Bender, Makana K (DOA) (makana.bender@alaska.gov)'; 'Brooks, Phoebe L (DOA) (phoebe.brooks@alaska.gov)'; Carlisle, Samantha 1 (DOA); 'Colombie, Jody J (DOA) Oody.colombie@alaska.gov)'; 'Davies, Stephen F (DOA) (steve.davies@alaska.gov)'; Eaton, Loraine E (DOA); Toerster, Catherine P (DOA) (cathy.foerster@alaska.gov)'; 'Frystacky, Michal (michal.frystacky@alaska.gov)'; 'Guhl, Meredith (DOA sponsored) (meredith.guhl@alaska.gov)'; Kair, Michael N (DOA); Loepp, Victoria T (DOA); 'Mumm, Joseph (DOA sponsored) Ooseph.mumm@alaska.gov)'; 'Paladijczuk, Tracie L (DOA) (tracie. pa lad ijczu k@a laska.gov)'; 'Pasqua1, Maria (DOA) (maria.pasqual@alaska.gov)'; 'Regg, James B (DOA) Oim.regg@alaska.gov)'; 'Roby, David S (DOA) To: (dave.roby@alaska.gov)'; 'Schwartz, Guy L (DOA) (guy.schwartz@alaska.gov)'; 'Seamount, Dan T (DOA) (dan.seamount@alaska.gov)'; Singh, Angela K (DOA); 'Wallace, Chris D (DOA) (chris.wallace@alaska.gov)' Subject: aio4f-006 (BPXA) Attachments: aio4f-006.pdf James Gibbs Jack Hakkila Bernie Karl K&K Recycling Inc. P.O. Box 1597 P.O. Box 190083 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 Well 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 �c.>1 Angela K. Singh Colombie, Jody J (DOA) From: Foerster, Catherine P (DOA) Sent: Monday, December 07, 2015 11:57 AM To: Colombie, Jody 1 (DOA) Subject: Re: aio4F.006.docx Approve Sent from my Whone On Dec 7, 2015, at 1:48 PM, Colombie, Jody J (DOA) <iody.colombie@alaska.gov> wrote: Please review and approve. Jody J. CoCom6ie .AOGCC Speci.aCAssistant .ACaska OiCand Gas Conservation Commission 333 'West 7t' .Avenue Anchorage, .A(aska 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.gov. <aio4F.006.docx> THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.007 Mr. Douglas A. Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-16-013 333 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 X-33 (PTD 1961440) to be online in water only injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) X-33 (PTD 1961440) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated April 5, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4F.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 state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on September 19, 2015 which indicates that X-33 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 5 psi/day and 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 4F.007 April 11, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU X-33 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 September 19, 2015. DONE at Anchorage, Alaska and dated April 11, 2016. 0 jz�h . t, 4 ;00*, C by I-ster Daniel T. eamount, Jr. C air, Commissioner Commissioner .TION 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. THE STATE 'ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 4F.007 Mr. Douglas A. Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-16-013 333 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 X-33 (PTD 1961440) to be online in water only injection service with known inner annulus repressurization. Prudhoe Bay Unit (PBU) X-33 (PTD 1961440) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated April 5, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4F.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 state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on September 19, 2015 which indicates that X-33 exhibits at least two competent barriers to the release of well pressure. The well has a recorded IA build up rate of 5 psi/day and 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 4F.007 April 11, 2016 Page 2 of 2 AOGCC's approval to continue water injection only in PBU X-33 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 September 17, 2015. DONE at Anchorage, Alaska and dated April 11, 2016. //signature on file// Cathy P. Foerster Chair, Commissioner //signature on file// Daniel T. Seamount, Jr. Commissioner 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: Monday, April 11, 2016 3:10 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); 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 Moora; 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); Teresa Imm; Thor Cutler; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Vicki Irwin; Vinnie Catalano; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Anne Hillman; 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; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; 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; Terence Dalton; Tina Grovier (tmgrovier@stoel.com); Todd, Richard J (LAW); Tostevin, Breck C (LAW); Vicky Sterling; Wayne Wooster; William Van Dyke Subject: aio4f-007 - BPXA Attachments: aio4f-007.pdf Jody J. CoCombie AOqCC SpeciaCAssistant ACaska OiCandCjas Conservation Commission 333 'Vest 711 Avenue Anchorage, ACaska 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 iody.colombie@alaska.gov. 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 Well 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 TA.z;�ek LTC- �( \3 , 2o�Qe Angela K. Singh THE STATE "ALASKA GOVERNOR BILL WALKER Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO.4F.008 Mr. Douglas A. Cismoski Well Intervention Manager BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Docket Number: AIO-16-019 333 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 14-27 (PTD 1831700) to be online in water alternating gas (WAG) injection service with a shallow packer depth (cemented inner annulus). Prudhoe Bay Unit (PBU) 14-27 (PTD 1831700) Prudhoe Bay Field Prudhoe Oil Pool Dear Mr. Cismoski: By letter dated April 25, 2016, BP Exploration (Alaska), Inc. (BPXA) requested administrative approval to continue WAG injection in the subject well. In accordance with Rule 9 of Area Injection Order (AIO) 4F.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 a potential production casing leak at 5714 ft and a tubing leak at 8170 ft with the well being shut in since 2004. BPXA performed diagnostics and performed a tubing punch (9043 to 9048 ft) and cement squeeze of the inner annulus under Sundry 315-536 in December 2015. The cement top was estimated at 3064 ft, with the upper injection perforation located at 9534 ft. BPXA performed a passing waterflow log on April 23, 2016 which indicates no upward movement of fluid in the IA across the cemented interval. However, since the inner annulus is cemented leaving only approximately 3064 ft of inner annulus available for monitoring, this annulus does not meet the requirement that an injection well be equipped with a packer set not more than 200' measured depth above the top of the perforations. If injection does not occur into, through, or above freshwater, 20 AAC 25.450 authorizes less stringent well construction and integrity requirements if AOGCC determines the reduction in requirements will not result in an increased risk of movement of fluids into freshwater. AIO 4F.008 May 23, 2016 Page 2 of 2 BPXA completed a passing non -state witnessed Mechanical Integrity Test of the Tubing (MITT) on February 24, 2016 and a passing non -state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on December 14, 2015 which indicates that 14-27 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. AOGCC's approval to continue WAG injection in PBU 14-27 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 perform a mechanical integrity test of the tubing every 2 years to the maximum anticipated injection pressure; 5. BPXA shall limit the well's IA operating pressure to 2000 psi; 6. BPXA shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 7. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 8. 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. �s h'V1. ib � , DONE at Anchorage, Alaska and dated May 23, 2016. Cathy IY Foerster el T. S mount, Jr. Chair, Commissioner Commissioner 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: Tuesday, May 24, 2016 9:06 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)'; Trystacky, 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) Qoseph.mumm@alaska.gov)'; 'Noble, Robert C (DOA) (bob.noble@alaska.gov)'; 'Paladijczuk, Tracie L (DOA)(tracie.pa lad ijczu k@ a laska.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) (ch ris.wal lace@ a laska.gov)'; 'AKDCWel lInteg rityCoo rd i nator'; 'Alan Bailey'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Amanda Tuttle'; 'Andrew VanderJack'; 'Anna Raff'; 'Barbara F Fullmer'; 'bbritch'; 'Becky Bohrer'; 'Bill Bredar'; 'Bob Shavelson'; 'Brian Havelock'; 'Bruce Webb'; Burdick, John D (DNR); 'Caleb Conrad'; 'Candi English'; 'Cliff Posey'; 'Colleen Miller'; 'Crandall, Krissell'; 'D Lawrence'; 'Dave Harbour'; 'David Boelens'; 'David Duffy'; 'David House'; 'David McCaleb'; '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'; 'Joe Nicks'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Houle'; 'Julie Little'; 'Karen Thomas'; 'Karl 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)'; 'Mary Cocklan-Vendl'; 'Mealear Tauch'; 'Michael Calkins'; 'Michael Moora'; 'MJ Loveland'; 'mkm7200'; Morones, Mark P (DNR); Munisteri, Islin W M (DNR); 'nelson'; 'Nichole Saunders'; 'Nick W. Glover'; 'Nikki Martin'; 'NSK Problem Well Supv'; 'Oliver Sternicki'; 'Patty Alfaro'; 'Paul Craig'; 'Paul Decker (paul.decker@alaska.gov)'; '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'; 'Steve Moothart (steve.moothart@alaska.gov)'; 'Suzanne Gibson'; Tamera Sheffield; 'Tania Ramos'; 'Ted Kramer'; Temple Davidson; Teresa Imm; Thor Cutler; 'Tim Mayers'; Todd Durkee; trmjrl; 'Tyler Senden'; Vicki Irwin; Vinnie Catalano; 'Aaron Gluzman'; 'Aaron Sorrell'; Ajibola Adeyeye; Alan Dennis; Ann Danielson; Bajsarowicz, Caroline J; Brian Gross; 'Bruce Williams'; Bruno, Jeff J (DNR); Casey Sullivan; D. McCraine; 'Don Shaw'; Eric Lidji; Furie Drilling; Garrett Haag; 'Graham Smith'; Hak Dickenson; Heusser, Heather A im Subject: Attachments: Please see Attached: (DNR); Holly Pearen; J. Stuart; 'Jason Bergerson'; 'Jim Magill'; Joe Longo; John Martineck; Josh Kindred; Kasper Kowalewski; 'King, Kathleen J (DNR)'; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; 'Marie Steele'; Matt Armstrong; 'Mike Franger'; Morgan, Kirk A (DNR); Pat Galvin; 'Pete Dickinson'; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; 'Ryan Daniel'; 'Sandra Lemke'; 'Susan Pollard'; T. Hord; Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Vicky Sterling; 'Wayne Wooster'; Whitney Pettus; 'William Van Dyke' Various Orders other110.pdf, aiol8C.010.pdf, aio5.025.pdf, aio4F.008.pdf Other Order 110 (Docket OTH-16-002) AIO 18C-010 (Docket A10-16-021) AIO 5-025 (Docket AI0-16-020) AIO 417-008 (Docket AI0-16-019) Jody J. Colombie AOGCC SpeciaCAssistant Alaska OiCandGas Conservation Commission 333 Nest 7`h .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 iody.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. Douglas A. Cismoski Richard Wagner Well Intervention Manager 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 2 a Angela K. Singh INDEXES L,.) by BP Exploration (Alaska) Inc. tn Ptost Office Integrity 1 r96612dinator, PRB-20 APR ) 9 2038 Anchorage, Alaska 99519-6612 ^^ OnG/'a//''++ C 0 February 13, 2018 Mr. Hollis French Alaska Oil and Gas Conservation Commission 333 West 71h Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Unit Well 04-09 (PTD # 1760300) Application for Cancellation of AID Administrative Approval 4F.003 Dear Mr. French, BP Exploration (Alaska) Inc. requests cancellation of NO Administrative Approval 4F.003 dated June 29, 2015. The administrative approval was for continued water injection into Well 04-09 with inner annulus by outer annulus communication. BPXA applied for a sundry on December 20, 2017 to request for well 04-09 to be converted from an injector to a producer. The Sundry (#317-601) was approved on January 17, 2018. Therefore, it is requested to cancel Administrative Approval 4F.003 for water injection only. If you have any questions, please call me at 564-4301 or Jack Lau/ Adrienne McVey at 659-5102. Sincerely, Oliver Sternicki BPXA Well Integrity Engineer Attachments: Wellbore Schematic Cc: Louis Romo Bill Isaacson Bernhard Stechauner Jack Lau/Adrienne McVey Ryan Daniel Aras Worthington Well Schematic Tfa&= 5"XT L FMCI V1E1JEAD= F6C ACTUATOR= BAKERC KB. BEV = 52.0 HF ELEV = 32.19 KOP= 3300 141c An* 61"x7578' Wtum MD= 11729 WtumTVD= 6800 SS 72I, Minknum D = 2.992" @ 10786' 4 112" NO-GO SETTING SLEEVE Vl TBG./ 7p. L-80,.0232 bPf. D=4.Mr 112' TBG SEAL ASS' w ISEA_S. 11)= 4.75' 14ia-a+nt DN suwwNv FEE LOG BFKS ON 05/02116 ANGI.FATTOPPERF 38"@11467 14k: ROO(10 Poduchon OB for hob= lon 2-112* 6 11478 - 11493 O 04!07117 j 10788' 2-V7 4 11580-116W C 1271497 4-/2' TBG. 12.6x, L-80,1152 tpf,1 2-1/8' 4 11600-11620 C 10!041)7 116110' 11n'OBP112/19I761 1220116 11620-11672 S DF26M 1229716 &ALD RALR91-SFK7WAR C,AP 11829 -11635 S 062696 01A5/17 2-117 6 11635-11654 C 11!1791 2-117 6 11666 - 11674 C 03.15106 2-117 6 11682-11696 C 03/15M6 2-718' 4 11752 -11792 C 09.3090 3-315 10 11807 -11824 C 0629165 3316' 1D 11840-11865 C 0629165 I9-516" CSG, 47x. 04680. O = 8.861' 1-4 14090' _. n• LNR CT, 9 U. L 60, 0067 LPI, D - 2.087 _ _ _. 11697• 3-1/2' DAVIS LV NOi DOUBLE VALVE SHOE 11 8' T LMR, 2914. L -6D 0371 bpi. 10-6.184' I12060' 04-09 SAFETY NOTES: HRS READINGS AVERAGE 126 ppm WHEN ON MI, WELL REQUIRES A SSSV WNENONNI. DEPTH DISCREPANCY BETWEEN B IM OPS -12^ SEAL ASSY AND TOP OF BOT PBR SEAL ASSY WAS INSERTEI AND TBG SPACED OUT PER RIG REPORT. 40LZ236- [ 15 1/2- CAMCO BAL-O SSSV NP. D = 4.562" MOTE: TBG GAP BETON EEN 10686' -10692' 10682' 10711' Sin'BOT P6RASSY,T%(P 0-98' X S12' BOT 3-H ROl 1077Y S/?X4-12'X0,0=3.866' 1o7es• r•BIOiMc4.MRHCR j 10788' Ia N WCEFUN $LV,D-21 10802' 4-171"CAMCO DB NP, D=3.813' 10614• 4-/2' TBG. 12.6x, L-80,1152 tpf,1 10816' at Q•11M4MTAL(BEFMCTLNE I 10790• H RM TT LOGGED8SaM 116110' 11n'OBP112/19I761 DATE REV BY I COMAENTS I OATF I REv BY I GOM ENFS 06111176 ORIGINAL COMPLETION 02/02/17 J1JMD ODRFE=TBGSFALASSY 0522766 Rt6O OM0-V M67JW ADFBFS(04AV17) 08148701 CRANK RN0 1220116 JRJM) SETOBP(12118/16) 1229716 &ALD RALR91-SFK7WAR C,AP 01A5/17 JUJW WFUTCMARGAPTD MOGAP RdID-DE BAY UNIT WELL: 9409 PEIaV Na- 1760300 ARNc: 50029 2D207 00 SEC 27, T11N, R15E, 325' FSL & 643' FEL BP E1(P10f3Wn (Alaska) 17 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 711 Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF BP Exploration (Alaska) Inc. to convert the pilot gas -cap water injection project to a permanent project. IT APPEARING THAT: Docket Number: CO-16-018 and AIO-16-042 Conservation Order 207B Prudhoe Bay Unit Lisburne Oil Pool North Slope Borough, Alaska January 26, 2017 1. By a letter received September 26, 2016, BP Exploration (Alaska) Inc. (BPXA) requested a conservation order and an area injection order authorizing continued gas -cap water injection (GCWI) into the Lisburne Oil Pool (LOP) for the purpose of enhancing recovery. On its own motion the Alaska Oil and Gas Conservation Commission (AOGCC) proposes to add an administrative action rule. 2. Pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled a public hearing for November 3, 2016. On September 29, 2016, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On September 30, 2016, the AOGCC published the notice in the ALASKA DISPATCH NEWS and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. 3. No comments were received, no one requested that the hearing be held, and the AOGCC determined it had sufficient information to act upon the request so the hearing was vacated on October 24, 2016. FINDINGS: 1. BPXA is the operator and a working interest owner (WIO) of the Prudhoe Bay Unit (PBU). Other WIOs include ConocoPhillips Alaska, Inc., ExxonMobil Alaska, Production Inc., and Chevron USA. 2. On June 4, 2008, the AOGCC issued administrative approval CO 207A.001 and AIO 4E.029, which authorized a pilot GCWI project for the LOP involving the injection of water into the PBU L5-29 well and monitoring the performance of offset wells. This Administrative approval was set to expire on July 1, 2011, but on June 17, 2011, the AOGCC issued administrative approval CO 207A.002 and AIO 4E.038, which extended the expiration date to July 1, 2016. 3. During the pilot GCWI project, BPXA injected approximately 22.1 million barrels of water into the PBU L5-29 well. This raised the average reservoir pressure in the pilot project area by approximately 300 psi. 4. Results in the offset wells have been mixed. Some wells saw increased production or suppressed decline and lowering of the gas oil ratio, while other wells that have seen water breakthrough have experienced decreased production due to increased water cut or production downtime associated with formation of gas hydrates. 5. BPXA estimates that the net benefit of LOP GCWI is on the order of 100 to 350 barrels of oil per day and 0.5 to 3 million stock tank barrels increase in ultimate recovery. These results are less than originally anticipated, and have resulted in the WIOs deciding that GCWI is viable for the LOP but does not warrant being expanded beyond the existing PBU L5-29 well. CO 207B January 26, 2017 Page 2 of 7 6. CO 207 was issued on January 10, 1985, and contains a rule specific to hydrogen sulfide measures. The AOGCC revised its hydrogen sulfide regulations in 1999. 7. CO 207 and 207A lack an administrative action rule, which is a standard rule in more recent AOGCC orders. CONCLUSIONS: 1. The LOP GCWI pilot project has shown that the concept is feasible and that overall it has increased daily production rates and should increase ultimate recovery. 2. Converting the LOP GCWI project from a pilot project to a permanent project will minimize waste and increase ultimate recovery. 3. Changes to area injection order 4F are not necessary in order to carry out continued GCWI at the LOP. 4. The AOGCC regulations on hydrogen sulfide operations provide adequate protection and a pool specific rule is no longer necessary. 5. The addition of an administrative action rule will aid in the proper oversight and development of the LOP. NOW THEREFORE IT IS ORDERED: Development and operation of the Lisburne Oil Pool are subject to the following rules and the statewide requirements under 20 AAC 25 to the extent not superseded by these rules. This order supersedes conservation orders 207 and 207A and all of their associated administrative approvals, except for CO 207.1. The records of those orders and approvals are incorporated by reference into this order. AFFECTED AREA: UMIAT MERIDIAN T10N, R13E Sections 1, 2, 3, 10, 11, and 12. T10N, R14E Sections 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 35, and 36. T10N, R15E All. TION, R16E All. T10N, R17E Sections 3, 4, 5, 6, 7, 8, 9, 10, 15, 16, 17, 18, 19, 20, 21, 22, 27, 28, 29, 30, 31, 32, 33, and 34. T11N, R13E Sections 1, 2, 3, 4, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T11N, R14E All. T11N, R15E All. T11N, R16E All. CO 207B January 26, 2017 Page 3 of 7 T11N, R17E Sections 3, 4, 5, 6, 7, 8, 9, 10, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T12N, R13E Sections 35 and 36. T12N, R14E Sections 13, 14, 15, 16, 21, 22, 23, 24, 25, 26, 27, 28, 31, 32, 33, 34, 35, and 36. T12N R15E Sections 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. T12N, R16E Sections 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36. Rule 1. FIELD AND POOL NAME (Source: CO 207) The field is the Prudhoe Bay Field and the pool is the Lisburne Oil Pool. Rule 2. POOL DEFINITION (Source: CO 207) The Lisburne Oil Pool is defined as the accumulations of oil and gas which occur in stratigraphic sections which correlate with the stratigraphic section found in the Atlantic Richfield -Humble Prudhoe Bay State No. 1 well between the depths of 8,790 feet measured depth and 10,440 feet measured depth. Rule 3. WELL SPACING (Source: CO 207) The well spacing unit shall be one producing well per governmental quarter section. No pay may be opened in a well closer than 1,000 feet to the pay opened in another well or opened in a well which is closer than 500 feet to the boundary of the affected area. Rule 4. CASING AND CEMENTING (Source: CO 207, Revised: CO 207.2) a) A conductor casing shall be set at least 75 feet below the surface and sufficient cement shall be used to fill the annulus behind the pipe to the surface. Rigid high density polyurethane foam may be used as an alternate to cement, upon approval by the Commission. The Commission may also administratively approve other sealing materials which are supported by sound engineering principles and performance data. b) Surface casing to provide proper anchorage for equipment to prevent uncontrolled flow, to withstand anticipated interval pressure and to protect the well from the effects of permafrost thaw -subsidence or freeze back loadings shall be set at least 500 feet, measured depth, below the base of the permafrost but not below 5000 feet true vertical depth. Sufficient cement shall be used to fill the annulus behind the casing to the surface. c) Surface casing types and grades approved for use through the permafrost interval include: CO 207B January 26, 2017 Page 4 of 7 1) 13-3/8 inch, 72 pounds/foot, L-80 Buttress; 2) 13-3/8 inch, 72 pounds/foot, N-80 Buttress; 3) 13-3/8 inch, 68 pounds/foot, MN-80 Buttress; and 4)13-3/8 inch, 68 pounds/foot, K-55 d) The Commission may administratively approve additional types and grades of surface casing through the permafrost interval upon a showing that the proposed casing and connection can withstand the permafrost thaw -subsidence and freeze back loadings which may be experienced. Evidence submitted to the Commission shall include: 1) full scale tension and compression testing: or 2) finite element model studies: or 3) other types of axial strain data acceptable to the Commission. e) Alternate casing programs may be administratively approved by the Commission upon application and presentation of data which show the alternatives are appropriate, based upon accepted engineering principles. Rule 5. COMPLETION PRACTICES (Source: CO 207). Wells completed for production may utilize casing strings or liners cemented through the productive intervals and perforated, slotted liners, screen -wrapped liners, gravel packs or open hole methods, or combinations thereof. The Commission may administratively approve alternate completion methods where appropriate. Rule 6. HYDROGEN SULFIDE (Rescinded this Order). Rule 7. AUTOMATIC SHUT-IN EOUIPMENT (Rescinded by Other Order No. 66) Rule 8. GAS VENTING OR FLARING (Source: CO 207) a) The venting or flaring of gas is prohibited except for operational necessities and for safety volumes set out in this rule; b) A daily average volume of 1,000 MCF per day is approved for the safety flare at the Lisburne Production Center; c) Volumes of gas to provide safety flares for additional facilities may be approved by administrative order upon proper application; d) The volumes of gas for safety flares may be decreased or increased by administrative order; and e) Gas flaring may be approved by administrative order during commissioning of new equipment, purging, and start-ups after major repairs or interruptions. Rule 9. GAS -OIL RATIO TESTS (Source: CO 207) a) Between 90 and 120 days after regular production commences and each six months thereafter a gas -oil ratio test will be taken on each well for as long as it produces oil; CO 207B January 26, 2017 Page 5 of 7 The gas -oil ratio tests will be for a minimum of four hours and shall be taken at the normal producing rate of the well; and The results of the gas -oil ratio tests will be reported on Form 10-409, Gas -Oil Ratio Test and will be submitted in January and July of each year. Rule 10. PRESSURE SURVEYS (Source: CO 207, Revised CO 207.11). All new wells shall have an acceptable pressure survey, as defined in part (c), taken prior to regular production or injection. One pressure survey per producing drillsite per year shall be taken. Pressure surveys from producing or water and gas injection wells may be used for this pressure requirement. Pressure surveys covered in section (a) may be substituted for a drillsite pressure. Acceptable pressure surveys include static surveys, RFT/FMT, pressure buildup and falloff tests, and multi -rate pressure transient tests in production or injection wells. Other quantitative methods may be administratively approved by the Commission. The pressure datum for the Lisburne Oil Pool is 8900 feet subsea. The Commission may administratively amend this datum or create an additional datum when more information is available on the reservoir. Data from the pressure surveys, along with additional pressure data obtained through proper management of the reservoir, shall be filed on form 10-412 by the last day of the month following the month that the pressure survey was obtained. Submitted pressure data shall include other information as necessary such as rate, time, depth, temperature, and well conditions to allow for a complete analysis of the pressure survey. The operator shall schedule an annual meeting with the Commission to review the pressure monitoring program and discus future plans for reservoir management. Rule 11. UNITIZATION (Source: CO 207) To ensure the protection of correlative rights and to prevent waste, the Lisburne Oil Pool shall be administered in accordance with the Prudhoe Bay Unit Agreement. Rule 12. PILOT PROJECTS (Source: CO 207) Upon application, the Commission may administratively approve field pilot projects, well production and injection tests and other filed operations necessary for the purpose of developing a prudent enhanced recovery method and reservoir depletion program. Rule 13. POOL OFFTAKE RATE (Source: CO 207) No more than 160,000 barrels of oil per day may be produced from the Lisburne Oil Pool. However when evidence can be presented to the Commission showing that a higher offtake rate will not affect ultimate recovery, the Commission may increase the daily offtake rate by administrative order. Rule 14. CONSERVATION ORDER NO.83-C (Source: CO 207) CO 207B January 26, 2017 Page 6 of 7 Conservation Order No. 83-C is hereby cancelled. Rule 15. ANNULAR PRESSURES (Source: CO 492, Revised by: CO 207.17) a) The operator shall conduct and document a pressure test of tubulars and completion equipment in each development well at the time of installation or replacement that is sufficient to demonstrate that planned well operations will not result in failure of well integrity, uncontrolled release of fluid or pressure, or threat to human safety. b) The operator shall monitor each development well daily to check for sustained pressure, except if prevented by extreme weather conditions, emergency situations, or similar unavoidable circumstances. Monitoring results shall be made available for AOGCC inspection. c) The operator shall notify the AOGCC within three working days after the operator identifies a well as having (a) sustained inner annulus pressure that exceeds 2500 psig for wells processed through the Lisburne Processing Center and 2000 psig for all other development wells, or (b) sustained outer annulus pressure that exceeds 1000 psig. d) The AOGCC may require the operator to submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action or increased surveillance for any development well having sustained pressure that exceeds a limit set out in paragraph 3 of this rule. The AOGCC may approve the operator's proposal or may require other corrective action or surveillance. The AOGCC may require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. e) If the operator identifies sustained pressure in the inner annulus of a development well that exceeds 45% of the burst pressure rating of the well's production casing for inner annulus pressure, or sustained pressure in the outer annulus that exceeds 45% of the burst pressure rating of the well's surface casing for outer annulus pressure, the operator shall notify the AOGCC within three working days and take corrective action. Unless well conditions require the operator to take emergency corrective action before AOGCC approval can be obtained, the operator shall submit in an Application for Sundry Approvals (Form 10-403) a proposal for corrective action. The AOGCC may approve the operator's proposal or may require other corrective action. The AOGCC may also require that corrective action be verified by mechanical integrity testing or other AOGCC approved diagnostic tests. The operator shall give AOGCC sufficient notice of the testing schedule to allow AOGCC to witness the tests. f) Except as otherwise approved by the AOGCC under paragraph 4 or 5 of this rule, before a shut- in well is placed in service, any annulus pressure must be relieved to a sufficient degree (a) that the inner annulus pressure at operating temperature will be below 2500 prig for wells processed through the Lisburne Production Center and below 2000 psig for all other development wells, and (b) that the outer annulus pressure at operating temperature will be below 1000 psig. However, a well that is subject to paragraph 3, but not paragraph 5, of these rules may reach an annulus pressure at operating temperature that is described in the operator's notification to the AOGCC under paragraph 3, unless the AOGCC prescribes a different limit. g) For purposes of these rules, "inner annulus" means the space in a well between tubing and production casing; "outer annulus" means the space in a well between production casing and surface casing; "sustained pressure" means pressure that (a) is measurable at the casing head of an annulus, (b) is not caused solely by temperature fluctuations, and (c) is not pressure that has been applied intentionally. CO 207B January 26, 2017 Page 7 of 7 Rule 16. GAS -CAP WATER INJECTION PROJECT (New this order) a) Water injection is authorized into Well L5-29 only and is limited to perforations within the upper Wahoo Formation (Zone 6) between the measured depths of 13,585' and 13,634'; b) The Well L5-29 injection rate is limited to 20,000 barrels of water injected per day; and c) Injection pressures must be maintained below 0.55 psi/ft. Rule 17. ADMINISTRATIVE ACTION (New this order) Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the Commission my 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 i freshwater aquifers. ©II' •sty: DONE at Anchorage Alaska and dated January 26, 2017. Cathy . F rester ie17S a ount, r. Hollis French , Chai , Commissioner Commissioner Commissioner 'It", DN 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. 16 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO-16-042 and CO-16-018 The application of BP Exploration (Alaska) Inc. (BPXA) to convert the Prudhoe Bay Unit's (PBU) Lisburne Oil Pool (LOP) gas cap water injection (GCWI) pilot project to a permanent project. BPXA, by letter dated September 26, 2016, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order authorizing the PBU LOP GCWI project as a permanent development project instead of the pilot project it is today. The AOGCC has tentatively scheduled a public hearing on this application for November 3, 2016, at 9:00 a.m. at 333 West 7t' Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on October 15, 2016. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 279-1433 after October 20, 2016. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 71" Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on November 1, 2016, except that, if a hearing is held, comments must be received no later than the conclusion of the November 3, 2016 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing contact the AOGCC at (907) 279-1433 no later than October 27, 2016. Cathy . Foerster Chair, Commissioner Diane Richmond Performance and Data Management Team lead BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 'Ql� Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO-16-042 and CO-16-018 The application of BP Exploration (Alaska) Inc. (BPXA) to convert the Prudhoe Bay Unit's (PBU) Lisburne Oil Pool (LOP) gas cap water injection (GCWI) pilot project to a permanent project. BPXA, by letter dated September 26, 2016, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue an order authorizing the PBU LOP GCWI project as a permanent development project instead of the pilot project it is today. The AOGCC has tentatively scheduled a public hearing on this application for November 3, 2016, at 9:00 a.m. at 333 West 7th Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on October 15, 2016. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 279-1433 after October 20, 2016. In addition, 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 4:30 p.m. on November 1, 2016, except that, if a hearing is held, comments must be received no later than the conclusion of the November 3, 2016 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing contact the AOGCC at (907) 279-1433 no later than October 27, 2016. Hsignature on fileH Cathy P. Foerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWNGADVERTISING ORDER NO.,CERTIFIED AFFIDAVII OF PUBLICATION WITH ATTACHED COPY OFADVERTISMENT. ADVERTISING ORDER NUMBER AO-17 —008 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 09/29/16 AGENCY PHONE: 1(907) 279-1433 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 TYPL1 F b LEGRL DISPLAY CLASSIFIED OTHER (Specify belovi . hU:' . Y. a'M., "h'.:s "1`� . d� .'" .� �' i �. .l:�iiG '&'P< :> u� A DESCRIPTION PRICE AIO 16-042 and CO-16-018 Initials of who prepared AO: Alaska Non -Taxable 92-600185 livY9TdHQ4�kNG:AKI R7isilvG -:::O:RDNB.No....... iEpA:F.R AV.Xr. F.:;: rtil3teattoN iv[Tit nTrAciEri corY Ili?: ......RTt.. ....... ::.:.:::...: .... ............. .... Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Page 1 of 1 Total of All Pages $ REF Type Number Amount Date Comments 1 PvN ADN89311 2 Ao AO-17-008 3 4 FIN AMOUNT SY Appr Unit PGM LGR Object FY DIST LIQ 1 17 021147717 3046 17 2 3 5 Purch ti le: Purchasing Authority's Signature Telephone Number O.A a cei n name must appear on all invoices and documents relating to this purchase. state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use ofthe state and not for ............. .......... Division Fiscal%Aii' `rial: A©::::..:... o iesc: Pti6lisheY .fazed :Division Fiscal a2eceivin :::::::: »:::::::: ... I . :::: %`::: %':::: %: : ............>................�.P..............(.....).................................................................. Form:02-901 Revised: 9/29/2016 270227 0001393657 $189.26 AFFIDAVIT OF PUBLICATION STATE OF ALASKA THIRD JUDICIAL DISTRICT Emma Dunlap 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 September 30, 2016 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. Subscribed and sworn to before me this 30th day of September, 2016 Notary Public in and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPIRES ca�&6ZaL/ CICI r 201 NOt"0' OF public Homing ALASKA STATE ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Numbers: AIO-16-042 and CO-16-018 The application of BP Exploratio I (Alaska) Inc. (BPXA) to convert thePrudhoe Bay Unit's (PBU) Lisburne oil Pool (LOP) gas cap water injection (GCWI) pilot project to a permanent project. �pXa oil and orisrcrmtheGas� by eryauisu C:omsl ((AOGCQ issue orts er to , me A permanent development project instead of pplicAation f rhivovetentative, 016 a 9: a.m. at 333 West 7ts Aver this Anchoragge, Alaska 99501, To request that the tentatively scheduled hearingS be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on October 15, 2016. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn d the AOGCC will hold the hearing, call 279-1433 after October 20, 2016. application ma be In addition, written comments regarding this appl' laska submitted o the AOGCC a be rec eived ved no later e'thAnchorage, :0 .m. on November Comments must except received no lather Tian the conclu ion of the No held comments, 20hear ng comment orattend tie 1�earriingacontactlthhee AOGCC at (`�7) neededations may be 79 3 no later than October 27, 2016. Hsi nature on file// Hsi P. Foerster Chair, Commissioner Published: September 30, 2016 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, September 29, 2016 2:41 PM To: Ballantine, Tab A (LAW); '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. pa lad ijczu k@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.wal lace@ a laska.gov)';'AK, GWO Projects Well Integrity'; 'AKDCWellIntegrityCoordinator'; 'Alan Bailey'; 'Alex Demarban'; 'Alexander Bridge'; 'Allen Huckabay'; 'Andrew VanderJack'; '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'; 'DNROG Units'; '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'; 'Joe Nicks'; 'John Burdick'; 'John Easton'; 'Jon Goltz'; 'Juanita Lovett'; 'Judy Stanek'; 'Julie Little'; 'Karl Moriarty'; 'Kasper Kowalewski'; 'Kazeem Adegbola'; 'Keith Torrance'; 'Keith Wiles'; 'Kelly Sperback'; Kruse, Rebecca D (DNR); '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'; 'Marguerite 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'; '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'; 'Tamers Sheffield'; 'Ted Kramer'; 'Temple Davidson'; '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; To: Subject: Attachments: Please see attached. '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 (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' Public Notice AIO-16-042 and CO-16-018 Public Hearing Notice.pdf Re: Docket Numbers: AIO-16-042 and CO-16-018 The application of BP Exploration (Alaska) Inc. (BPXA) to convert the Prudhoe Bay Unit's (PBU) Lisburne Oil Pool (LOP) gas cap water injection (GCWI) pilot project to a permanent project. Jody J. Colofnhie AOyCC Special .Assistant ✓Alaska Oil ana`Las Conse►-1�ation Commission 333 West 7"' _Avenue .Anchorage, Alaska 9�a5on O ice: (,907) 793-I221 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. 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 �eL 15 ' r T ZE BP Exploration (Alaska) Inc. P. 0. Box 196612 900 East Benson Boulevard Anchorage, AK 99519-6612 September 26, 2016 Cathy P Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Re: Final Report and Application to Convert Pilot to Permanent Status Conservation Order 207A.002 and Area Injection Order 4E.038 (now 4F) Lisburne Gas Cap Water Injection (GCWI) Pilot Project — Well L5-29 Lisburne Oil Pool, Prudhoe Bay Unit Dear Chair Foerster: BP Exploration (Alaska), Inc., as operator of the Prudhoe Bay Unit and on behalf of the working interest owners, submits the attached Final Report of the referenced pilot project, and requests that the Commission amend its prior orders to authorize continued GCWI into the Lisburne Oil Pool. We submit the attached Final Report for Lisburne Gas Cap Water Injection Pilot Project at L5-29 Well (07101114 — 07101116) pursuant to Conditions 4 and 5 of Conservation Order 207A.001 and Area Injection Order 4E.029, dated June 4, 2008. The Final Report discusses and documents the GCWI pilot period, and demonstrates that this GCWI method is a viable enhanced oil recovery process that leads to greater overall recovery from the Lisburne Oil Pool. The GCWI project going forward is not expected to be expanded to other areas of the Lisburne Oil Pool. The project will target water injection rates up to 20,000 bwpd in L5-29 for an estimated incremental oil recovery benefit of 100-350 bopd, or 0.5-3 MMSTBO. We request that the maximum injection limits be removed from the referenced commission order to allow for greater operational flexibility as our understanding of the reservoir progresses. We respectfully request that the Commission approve this request and make the referenced GCWI pilot project permanent, rename it the Lisburne GCWI Project, and allow GCWI into the Lisburne Oil Pool gas cap through Well L5-29 for enhanced Lisburne oil recovery. We propose to include an update of the Lisburne GCWI Project as part of the Lisburne Oil Pool Annual Surveillance Report, due June 15`h of each year. Application to Convert Pilot Project to Permanent Status CO 207A.002 AIO 4E.038 (now 417) September 26, 2016 Page 2 Should you have any questions regarding this request please contact Bill Bredar at 907-564- 5348 and William.bredar@bp.com. Sincerely, 46- 'A Diane Richmond Performance and Data Management Team Lead Enclosure: Final Report for Lisburne Gas Cap Water Injection Pilot Project at L5-29 Well cc: Mr. Eric Reinbold, ConocoPhillips Alaska, Inc Mr. Phil Tsunemori, ConocoPhillips Alaska, Inc Mr. Hank Jamieson, ExxonMobil Alaska, Production Inc Ms. Katherine Motteram, ExxonMobil Alaska, Production Inc Mr. Gerry Smith, ExxonMobil Alaska, Production Inc Mr. Phil Ayer, Chevron USA Mr. Dave White, Chevron USA FINAL REPORT FOR LISBURNE GAS CAP WATER INJECTION PILOT PROJECT AT L5-29 WELL (07/O1/14 - 07/01/16) RESPONSE TO CONDITION NO. 5 UNDER ALASKA OIL AND GAS CONSERVATION COMMISSION ADMINISTRATIVE APPROVALS CO 207a.001 & AIO 4E.029 Submitted by BP as Operator on Behalf of the Prudhoe Bay Unit Working Interest Owners Dated: 9/01/2016 Executive Summary The Lisburne L5 Gas Cap Water Injection (GCWI) pilot project began in July 2008 and terminated July 1", 2016. Progress reports were submitted in 2011 and 2014 to the Alaska Oil and Gas Conservation Commission (AOGCC). This report will primarily cover the period following the last progress report, comprising the period of July 1st 2014 to July 1 st, 2016, as well as give a final overview of the pilot. Through the course of the pilot, 22.1 MMBW were injected into L5-29, a volume nearly two and a half times the volume of water injected during the L2 waterflood pilot of 1987- 1989. The GCWI pilot met the original five objectives of the pilot, however individual well performance was not consistent in behavior: Oil production has increased or decline has been suppressed in some of the offset wells. Pressure has increased approximately 300 psi since the start of the pilot. Gas/Oil Ratio (GOR) has been suppressed in some offset wells. L5-29 has been capable of injecting the desired rates during the pilot. Although hydrate problems related to GCWI occurred in some offset wells, it currently is providing a net positive oil benefit on the order of 100-350 bopd. This benefit has mostly been through sustained or increased fluid rates associated with higher reservoir pressure and suppressed gas rates. Although this is less than the aspired benefit of about 2,000 bopd, it has proven a greater technical success than the original L2 waterflood pilot. As the GCWI process has been successful in increasing oil production in the L5 area, the operator recommends continuing to inject into L5-29. At this time the Prudhoe Bay Unit working interest owners do not plan to expand the program of GCWI to other locations in the field due to the current low benefit and high cost of implementation at other drillsites, and scarcity of viable locations. Introduction Objectives The Lisburne L5 Gas Cap Water Injection (GCWI) initial pilot project had the following objectives: 1. Increase Lisburne oil production rates (primarily from L5 pad wells) 2. Provide pressure support to the Lisburne Reservoir, primarily in the L5 pad area 3. Reduce produced gas / oil ratios of L5 pad wells 4. Determine water injectivity for Lisburne wells 5. Evaluate gas cap water injection as a process that has potential to be expanded to other areas of the Lisburne gas cap to recover additional Lisburne oil Geologic Setting The Lisburne Field is the only producing carbonate field in Alaska (Figures 1 & 2). It is located approximately 250 miles north of the Arctic Circle at latitude of 71 ° N. The Lisburne Oil Pool encompasses some 39,200 acres (61 square miles). A significant portion of the Lisburne Oil Pool underlies the Prudhoe Bay Permo-Triassic reservoirs, separated by shale sequences. The Lisburne field was discovered in early 1968 with the drilling of the Prudhoe Bay State #1 well by ARCO and Exxon. The Lisburne Oil Pool is defined by Rule 2 of Conservation Order No. 207. It is the accumulation of oil and gas found within stratigraphic sections that correlate with the stratigraphic section occurring in the Atlantic Richfield -Humble Prudhoe Bay State No. 1 well between the depths of 8,790 feet measured depth and 10,440 feet measured depth. The Lisburne Reservoir is a combination structural and stratigraphic trap of carbonate lithology. It is an anticlinal structure that is bounded on the north by the Prudhoe Bay- Niakuk fault complex, by the Lower Cretaceous Unconformity (LCU) truncation to the east, and by the Pre-Echooka Unconformity (PEU) truncation to the west. The unitized intervals are of Mississippian / Pennsylvanian age and include the Alapah and Wahoo formations of the Lisburne Group. Over the past eight years, the L5-29 GCWI Pilot Project injected seawater only into the Wahoo formation. }ter LISBURNE FIELD WAHOO RESERVOIOIR-DRILL SITE LISBURNE LSEV �� a oe +3* a #1 o,! .. �CWI Ih!{tb11 WeR x '� �i lS-S7 5 34 Q d4E r Q Q� Tf3TAL DEPTH'✓ aL LC ATiON ' Ll_: s.a waer wr ! Figure 1: L5-29 Gas Cap Water Injector Location Plat Local Geologic Highlights for the L5-29 Area The area around L5-29 is geologically unique for the Lisburne field. Logs indicate 40%+ porosity enhancement locally (Figure 3) at the top of Wahoo Zone 6 from LCU exposure in the northernmost fault block. Wells L5-29 and L5-36 experienced large lost circulation events while drilling through this interval, and the drillers described it as a "cave". This super-porosity/permeability enhancement around L5-29 and L5-36 is not representative of matrix properties anywhere else in the field. The porosity enhancement is constrained by the Prudhoe Bay fault to the north and other major east -west faults to the south that appear to form a permeability barrier / baffle (Figures 4A, 4B and 4C). 5990.m0 =pm 5mpm BE DEC s96s.mo s9m,mo 5XI.t0 5.970.000 A 5965.m0 f s9w,ugp 5965,m0 59w,m0 � Y If 596.m0 .--`WEST BEACH 02 .VL LS L0I-12 f G1I GI8.06b5, 'd----^'"�'r ----y-_. Lt®-27 & J LS-25,_ 33 LC 28 L6-, C 5 i LGI-02 L -28 v '3J• L5-26 L 1 1 O L1-30 3 L 21 "5 31 LS-3215-24 Ll � �1 � 178 L1 13`' L Q .. 40-14 L5-p8 er 1t 1(,3LI-15 -? L110 LGI* 1 17 Lb16 i ® 93 j 3-0T V L 01 LJ33 LJ3.26 L3-05 ' LI 08 L OL 02 L4--12 L2-25L i L2-2 18 L3-12 L2`-21WJ)6L L 11 1 3 18 LbO3L608 10L�4 LA-li LZ' LPC-02L© 15 L -1 L — L4b11 1J V E9 L3-24 L2-10 W gp L -15 L2=03 LWL}30 - L-01 i ° L631 L 8 L4-31 L4 pp L4-36 8 6mpm wpm 6wpm Rspm 670pm 675 pm 6wpm 65 pm E&Opm E55pm 7mpm ius pm 710pm 741 7mpm 725pm 7mpm 136.0m 710p00 i15pm Figure 2: Lisburne Field Fluid Contact Base Map with GCWI Pilot SP EXPLORATION WA MI 1 s t Figure 3: Log Suite Showing High Porosity at Top of Zone 6 Below LCU Gull-02 L5-29 L5-33 L5-18 W E 8000 Z7 �LCU 8500 Z6 Z5 Z4 ..4.. Z3 9000 /Z2 cn Cn 9500 10000 Figure 4A: L5 West to East Structural Cross -Section L5-29 L5-33 NW SE 8500 L5-31 L5-13 9000 Z7 Z6 Z5 9500 Z4 Z3 /Z2 10000 Cn 10500 Figure 413: L5 Northwest to Southeast Structural Cross -Section LS-29 L5-36 \\ -28A L5-33 L5-25 L5.28 GULL-02 -2 LS•26 �\ L5-23 ` 5-21 L5-3 / 7k t� LGI.04 ] 1000 20M 3000 4000 Figure 4C: L5 Pad Location Map for Structural Cross -Sections in Figures 4A and 4B LS-18 Surveillance and Performance Summary of Surveillance Activities As a part of GCWI surveillance, Static Bottom -hole Pressures (SBHP) were measured in offset producers. L5-29 wellhead pressures and well performance of online producers were also monitored. Injection History Figure 5 illustrates the injection rate history along with periods when the injector was shut in during the reporting period of July 2014 through July 2016. As of July 1, 2016 the cumulative water injection reached 22.1 MMbbls. The current plan is to attempt to repair the well and continue injection. 20,000 18,000 16,000 0 14,000 a. m 12.000 10,000 0 8.000 .0 6,000 T 4,000 0 2.000 0 -f "N L5-29 Injection L. 11,■ J Shut-in for choke change I It Shut-in for well integrity �,b ,'t �a �6 �5 �h Ny �6 N6 No tk\"\fp 1\�\�O NON, 1\-'\20\1��0 '�\�\�O A��\�O 1\��0 Figure 5: L5-29 Seawater Injection Rates for current reporting period Daily injection rates are plotted against wellhead pressure to investigate changes in L5-29 injectivity as shown in Figure 6. The rates and corresponding wellhead pressures are color coded by date. Figure 6 depicts a significant decrease in injectivity from year 2014 to 2015. This change does not represent the reservoir behavior as it is caused by installation of a different choke. 1Jto 1200 stx� ■ 3 600 ■ w 400 ■ 200 i ■ r i � ■ ■ 0 L5-29 WHP vs Injection Rate _._ "okeC 1n /2014-6AOi2014 ■ 7/1!2014-12i3l/2014 s 1A 2015-6i30i2015 7rl?2015-12i31/2015 i - 1:1.-2016-6; 30i 2016 8000 10000 12000 14000 16" 18000 pOp Daily Injection Rate jbvpd j Figure 6: L5-29 WHP vs. Injection Rate Static Bottom -hole Pressure Frequent static bottom -hole pressures were measured for surveillance in the offset producers and showed pressures increased by —100-150 psi in the first row of offset producers (Figure 7) during this reporting period,—350-400 psi in total increase in pressure from 2008. The pressure increase shown on Figure 8 is likely due to a combination of lower withdrawal rate and the pressure support from the GCWI pilot well. Recent production from these wells is lower than before the injection start-up, and the entire L5 drillsite was temporarily down due to corrosion in the pad production export line during the reporting period. 1st Row of Producer 5-29 J.5-36 ' s-2s - 1J5�-)(3�'3zols 8AL1 L5-26�9-285-2315-21 t 5-32 J-5-24 J-1-14 _ — U-09 LGI-04 1_5-15 -" 17A__ LS-16A J-2-32 J�5-05 " J_541 J_5-12 _ _ -- _ 12-34 J.2-28 J_3." _ t J_5-08 L5-04 J-4-12 J.2-26 _ " 1:4-42 Figure 7: First Row of Producers Location Map with Year of Seawater Breakthrough L5-23 ■ L5-28 . L5-21 . L6.31 ■ L5-33 • L6.36 2 L5.28A Prod Ras bbl Rate—LS-29(GCYN)Injectlon Rate 3900 — 70000 3850 3800 60000 3750 ■ 3700 3650 50000 -_ 3600 ■ e6 m 'a 3550 a 3500 ■ • 40000 a x pp 3450 C ,"- 3400 30000 a y 3350 161, a 3300 -- -- am' 11 3250 -- - - 20000 3200 - - 3150 10000 3100 3050 - - - 3000 - 0 99 00 01 02 03 04 05 06 07 08 09 10 11 12 13 14 15 16 Figure 8: Static BHP/Production Plot for First Row of L5 Pad Producers Well Performance Figures 9-17 depict the production performance history of five offset producers. The top plot in each figure is well test information (oil/water/gas rates and GOR/WC), and the bottom plot shows monthly average GOR vs. cumulative oil production on the X-axis. Presently, the signs of incremental oil benefit during the GCWI pilot are based on the individual well production history, and are on the order of 100-350 bopd. This benefit has largely been from suppressed GOR, and increased fluid rates. Not every well surrounding L5-29 has shown a positive benefit, as associated water production has caused hydrate problems in some of the offset wells. Well performance trends have also been masked or affected by other factors outside of GCWI such as pad and facility downtime. Figure 18 is a semi -log plot of GOR vs. cumulative oil production for L5-23, L5-28A, L5-31, L5-33, and L5-36 combined. The pre-GCWI trend is drawn to show GOR increase with respect to the cumulative oil production. The flattening of GOR trend (circled in the figure) since the injection began may be an indication of improved recovery. GOR trends may also be artificially affected by the facility limitations and the maturity of many wells across multiple fields. Seawater breakthrough took has been observed in producers L5-28A, L5-32, L5-33 and L5-36 (Figures 13, 15, 16, 17). Observed estimated benefits and comments may be found in Table 1. MYM: l617A IQ: 1.677A TWO. awl i*.,.t W Cap? M W�i:.011bOroO.2 TYb 100tR290 ,,, Do No 80000,� soo J—0 ;00 140 er RatGOR ft00�pd1 (sctronl) E00D0 50 9 --� Increaseh Oil Rate ,oM aoo " �► 30009 � u m ono Gas fate Watercutl%1 3D0 zoo z tr jai Ls�cjfjd t0000 +D o 0 DE oe m oa oe tD 2to t, 1E ie D -1�t�Ta oeaw o-:all Tp Ou aw wlmq-M1ti Tn Vi.xw R.d o—tatlTn WRIb�001i z-tail T.t wG (%! ,. x - fi/at1 tOpD00tt1}T- t t t � t GCWI Start-up --' 2011 ,�,,,+ •0000 r0000 r e0000 Year iov ;oa 209E 2 E00 GOR//��,�,, . Doo �.+ (�/bbl) t89B 30000 # moon �- 10900 � 99E 992 989 sae 0 0 ooa .:are... 0 150 0 $00 O W 0 000 0 in0 0 800 10 Cumulative Oil Production (MMSTB) i '.0 1.3E EO Figure 9: Well Performance: L5-17 'too— Watercut �%) 1 _T.. ., _.. . i..... ,. 4GCWI Start-up :eo0 +.a0 72U— Water Rate )bwpo) GO ,Oo,_L!L.Rate_._. ibopol OQ e00 t� oo o Gas 1 Lsctdj 00 Or 02 03 0, De 07 Oa 09 �Li:TR QiRpf �Atl T,{pp Rat1 t.60r1L,i Trt WNN R.M �;RtI TR ti9R;W GDii �..RiI TN W.'.Ih. I I U1 irr»ro 'In. 117..11 n..�r. ,O et f2 13 ,♦ f5 ea --. .. _.. _. _._... ...-.. . .v._n .., ♦.�i v11 `IV I IV t_JI LJ/ — _el — — __ •♦ -1 1 %.illll111A11LC. 1-j —Irl 'WOOD '00 j t0000 30 0 'a" Oa eaNO e0 0 W6 p 30000 300 ZWWWO 204 a ,o4Oo Figure 11: Well Performance: L5-23 •— G Start-up woo 0 Oil Rate xCWI ,— (bopdj ° R (sd/bbi) oo ,z+� - 4 1000-r w f! aoo x coo 1 n .Do + e Water Rate 200... (bwpd) - e 00 oc 07 10 1LI)Tx01, Rn. :.-(R I) TO0., RM. Ud'UIO-{L,)TYWa Rm °-iR,yTx0011/W'b011 x JUJTNWCft 10o(R: 90000 goo Watercut (%) a0ooc Incfeasein • �0 ercut F °Q sow Watvim i .00 o a0000 n o 4 � 300 20000 g 200 Decrease in �` z Rat Gas Rate ( = 10o ajr A- 0ow 00920 0134 oaM a. a.� Cumulative Oil Production (MMSTB) Figure 13: Well Performance: L5-28A +tl00 rt S0O'�' +QQQrt Start-upWaterRatetlow 90000 Oil Rate (bopd) GOR 00 (�+Pd)(scflbbl) �= eoo rGCIII soo moo,000Gas Rate w000 scfd w o omo Watercut(%) 4. 00 0' 01 0] Oa � ,�m Do Q OS —ill}Tx CURw-+YR+�lx 68s R•p ;.y eiv—iL t', TY1 ri•tat A•H 0`TAGOArWCbl, Oe �] i. iQ 0 X—IR7)Ttt WC 1% t00000Lt� t + ! + � it•Pt, 9000'+ 8000o rt GCWI Start-up TOtt '0000 + Q0000 + m08 moo _ �Q. Year •0000 — A000 + moon — P9tl i 1 f �0°00 Iscubbl) 0 <esz ee4 Dom ) o aye 0.a9 Q -w n Qe] sea Cumulative Oil Production (MMSTB) f-- — — -• • • .•.. a.x 1V1 lllgll\.G• LJ-01 /Mme:1632 W US32 'YW Baa FotMFliOi °a4Y Of BOR4_DNir P+oe .1 OIYY art -up GCWI StSoo a° ,00 t soo0a a0 0 Oil Rate aoo + (bopd) 'coos '00 + + Wier Rate GOR w00° ( pd) (Sc(/bbl) increases o S000a °0 ° °0P i ", Dec ease in 50o0a xo +oo T ♦ a jj a I e ,7� a a oe A tat 2°00° aw + G ... •. V g Watercut(%) Gas Rate `oa00 1Y9 o er � scfd fit; Tn (hi RF+e ,...;R1:T%Ou R«.,w.$)O—,i:T„:'f�)«Rs+e �.R•T,: :wft stl xai: %—�R:TU Wu. Y.', ++ GCWI Start-up ,ef. eo0oo i i zo„ '0000 4 De4re YaOa in e0000 } i - GO 0ooe �4a0a ?' !985 Yea 30000 + i 2MO + i ux Doom scf/bbl 1959 gas 0 °�R,,)•.R,, oaac .� - aem - - Dew ,. ,w •ea use :21 :.a: zoo Cumulative Oil Production (MMSTB) Figure 15: Well Performance: L5-32 __.._ .. T -- ----- - ---- -- M.— ro mr �e.a� u•as ryP.' 8—rc.,er. Inteene asoxxt. nm wo6. s �r --------------_—.. ____.._----------_-- °aa t--- GCWI Start-up �ao�Rz 900 A Rate � o .wc + bopd) 14— Water Rate .gaoo %o a :oc — (bwpd) 41 GOR s8800 (scf/bbl) too �p1 wa too+ T gQ 6 i }� 29w0 9 � ®i l`l`l•:rrr � Gas Rate w o 2aa� I watercut(%) 989a °6 0 Of a= a° F77.77an-.,--P,'�T�iGu ky, ,W aIV-+l! i '.rr[.. k.i. 0-.01�TIGC.k+ c, X-2 Ty):•,-. 1 9aoaor GCWI Start-up J_ moo 2a+• =a eo-nao .- w:roa-�•---- —1 Year i6'B zaa± wood - GOR ooz (scf/bbl) 30000 — 2ooao — iaam ................. ... 11 q1z � +99^ +99: 999 Cumulative Oil Production (MMSTB) - +9se - Tigure 16: Well Perfnrmanvi- T, -11 7; GCWI Start-up x watercutN�, 00° — increase in too Watercut aterRat ebb 200 —. (bwpd) Oil Rate GOR No ( _eono wood o w6 fQj� v o awP �j n g wo �$ ° a0000 aoo A a Gas Rate .00 n ( � am a 44 fl y 3 ° +pp00 200 00 01 Oz Ob 0s W W v+ M M 10 „ 52 Ir- ,T+, QA a•u :,-tRs5 Tx 6•.Rw t•d,a50-il,)TCWlW Rw O-1R1i rrt OOalW,b01; x-Mi: +v�'NC R, t00000ru.-� 5. _ 5 5 t 90DW r wow T6w0 r OODw y 300w � .DODO GOR tODOP (Wbl) 0 GCWI Start-up Year L— .•...•.. Cumulative Oil Production (MMSTB) Figure 17: Well Performance: L5-36 20" 2008 "o0 IFIM I- 1W "2 040 26, 2 No it m LL u N 6 %r Cumulative Oil Production (MMSTB) hL� ten_ r ■ .su.v, moo. %-umbliieu GuR vs. 1,umuiative un Yroduction for L5-23, L5-28A, L5-31, L5-33 and L5-36 Table 1: Estimated Benefit of L5-29 on Nearby Wells L5-29 Gas Cap Water Injection Estimated Benefit Well Estimated 2016 IOR bo d Breakthrough Year Approximate Distance ft Comments 1-5-17A 100 N/A 7400 Well has increased in oil production, althou h also has had Ion eriods of bein shut in for as production. L5-21 0 N/A 4650 Well has a history of hydrate problems, and was offline from January 2008 to May 2016 due to integrity problem which has since been resolved. L5-23 25 N/A 5300 Fluid rate decline became near zero in 2009. L5-25 0 N/A 4250 Non -operable well, has been shut in for almost an of pilot and a reservoir P8A has recently been executed. L5-28A 200" 2013 6150 Well was previous y high gas rate we with ow ontme. Well now has much over gas rate, but a so a higher watercut and now requires a gas lift line (pending installation). Benefit derived from increased ontime and lower GOR. Estimated benefits assume successful well after adding gas lift. Due to poor ontime while waiting for gas lift, actual 2016 benefit Is near 0 bopd. L5-31 0 N/A 5900 High GOR well with low ontime and hydrate problems. Shut-in since 2012. L5-32 50 2015 9235 Benerd may be from injection in LS-1312,800 It away). Well recently cycled on (June 2016) at higher fluid rates and reduced gas production. Well will now likely require installation of gas lift line with the higher WC and lower GOR. Evidence of seawater production not obtained until July 2016, but earlyshift in trends be an in Fall 2015. L5-33 25 2009 3550 Well has had hydrate problems since 2009, and has not been able to sustain production since 2010 despite multiple hydrate remediation attempts. L5-36 -30 2011 5000 Well developed hydrate problems with the water production and has had trouble sustaining production despite hydrate iremediation attempts. Higher watercut has also offset increased fluid rates, resulting in an overall lower oil rate. Conclusions Estimated Resource Recovery 1. Reservoir pressure has increased around L5-29, resulting in greater fluid production rates. 2. GOR suppression has been observed in several of the offset wells, creating an incremental benefit, even if the oil rate did not increase. 3. Increased watercut in some of the wells has created hydrate problems resulting in deferred production and increased remediation costs. 4. Increased watercut in some of the wells coupled with the favorable reduction in gas rate has created the need for gas lift. 5. Changes in well performance, both favorable and negative around L5-29, have often been sudden and rapid, making long term predictions difficult. a. Current observed net incremental rate from L5-29 is estimated to be in the range of 100-350 bopd, compared to original expected benefits of 2,310 bopd. b. Incremental net recovery benefits currently are estimated in the range of 0.5 to 3 MMSTB, compared to original predictions of 1-12 MMSTB c. Unforeseen facility and well problems resulting in injector and producer downtime obfuscates some of the well trends and producer -injector interactions. d. L5-29 may have larger field -wide impacts that are more difficult to quantify due to a combination of cycle, full-time, and offline wells spread over multiple drillsites. Plan Forward for GCWI 1. Attempt repair of injector L5-29. 2. Request AOGCC permission for permanent injection into L5-29. 3. Continue monitoring wells in the area to maximize performance and recovery. 4. The Prudhoe Bay Unit working interest owners at this time do not plan to expand GCWI outside of L5-29, however, the owners periodically review future opportunities as new information is acquired through time and understanding of performance changes. 14 Wallace, Chris D (DOA) From: AK, GWO SUPT Well Integrity <AKDCWeIIIntegrityCoordinator@bp.com> Sent: Friday, October 07, 2016 1:01 PM To: Wallace, Chris D (DOA) Cc: AK, GWO SUPT Well Integrity Subject: RE: aio4f-004 (PBU 13-06A) PTD 1972180 Chris, My original request was to both withdraw the recent request for amendment, and cancel the AA. But upon further consideration, your preferred course of action is a better path forward. I wish to withdraw the recent request to amend AIO 4F.004, and keep the well shut in under conditions of Administrative Approval AIO 4F.004. Thanks, Adrienne McVey Well Integrity Superintendent — GWO Alaska (Alternate: Jack Lau) 0: (907) 659-5102 C: (907) 943-0296 H: 2376 Email: AKDCWellinteeritvCoordinator@BP.com From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.gov] Sent: Friday, October 07, 2016 8:19 AM To: AK, GWO SUPT Well Integrity Subject: RE: aio4f-004 (PBU 13-06A) PTD 1972180 Adrienne, We need to confirm the language. Do you wish to: 1. Withdraw the recent request (to amend the existing AIO 4F.004) and keep the well shut in under conditions of Administrative Approval AIO 4F.004? Or 2. Withdraw the recent request (to amend the existing AIO 4F.004) and also request to cancel the existing AIO 4F.004? Cancelling the AIO 4F.004 implies the well is compliant with AIO 4F and the AOGCC regulations which I dare say it isn't. My preference would be to keep the well under AIO 4F.004 (monthly reporting etc) until the well condition can be clarified. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.Fov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: AK, GWO SUPT Well Integrity [mailto:AKDCWellintegrityCoordinator@bp.comj Sent: Thursday, October 06, 2016 6:54 PM To: Wallace, Chris D (DOA) <chris.waIlace @alaska.gov> Cc: AK, GWO SUPT Well Integrity<AKDCWelllntegrityCoordinator@bp.com> Subject: RE: aio4f-004 (PBU 13-06A) PTD 1972180 Chris, While performing recent prep work for setting the tubing patch, the well began to exhibit signs of tubing x OA communication. I would like to request the AA be cancelled. If you agree, we will submit a request for a new Administrative Approval once we've established two competent barriers. I'll make sure we send the associated MIT forms to the distribution list prior to submitting the request. In response to your comments and question below: The Request for Amendment should have referenced the final MIT -IA test pressure of 2258 psi, not the starting pressure of 2500 psi. I apologize for the oversight. The maximum anticipated injection pressure for water service is 2000 psi, based on data from 2004 — 2014. Please let me know if you have questions or need more information. Thanks, Adrienne McVey Well Integrity Superintendent — GWO Alaska (Alternate: Jack Lau) 0: (907) 659-5102 C: (907) 943-0296 H: 2376 Email: AKDCWellintegrityCoordinator@BP.com From: Wallace, Chris D (DOA) [mailto:chris.wallace(&alaska.gov] Sent: Thursday, October 06, 2016 3:21 PM To: AK, GWO SUPT Well Integrity Subject: FW: aio4f-004 (PBU 13-06A) PTD 1972180 Jack, Adrienne, We have received the request to amend this AA based on additional sundry work and test results. Please provide (to the distribution list on the AOGCC MIT form) the mentioned MIT-T completed on 8/20/16, with final pressure of 2587 psi. Please provide (to the distribution list on the AOGCC MIT form) the mentioned MITIA completed on 8/20/16 with a final pressure of 2258 psi. Please note that the 9.7% drop from the starting 2500 psi almost fails based on the 10% pressure drop rule. Please also not the final test pressure achieved of 2258 psi achieves a test pressure of 2258 and not the 2500 psi the amendment to the AA requires/requests. Please provide the TIO raw data or estimate the maximum injection pressure for this well. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7`h Avenue, Anchorage, AK 99501, (907) 793-1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.gov. 13 Colombie, Jody J (DOA) From: Wallace, Chris D (DOA) Sent: Wednesday, July 05, 2017 11:11 AM To: Colombie, Jody J (DOA) Subject: FW: aio4f-004 (PBU 13-06A) PTD 1972180 From: AK, GWO SUPT Well Integrity [mailto:AKDCWeIIlntegrityCoordinator@bp.com] Sent: Friday, October 7, 2016 1:01 PM To: Wallace, Chris D (DOA) <chris.waIlace@alaska.gov> Cc: AK, GWO SUPT Well Integrity <AKDCWeIIlntegrityCoordinator@bp.com> Subject: RE: aio4f-004 (PBU 13-06A) PTD 1972180 Chris, My original request was to both withdraw the recent request for amendment, and cancel the AA. But upon further consideration, your preferred course of action is a better path forward. I wish to withdraw the recent request to amend AIO 4F.004, and keep the well shut in under conditions of Administrative Approval AIO 4F.004. Thanks, Adrienne McVey Well Integrity Superintendent — GWO Alaska (Alternate: Jack Lau) 0: (907) 659-5102 C: (907) 943-0296 H: 2376 Email: AKDCWeIIlntegrityCoordinator@BP.com From: Wallace, Chris D (DOA) [mailto:chris.wallaceCabalaska.gov] Sent: Friday, October 07, 2016 8:19 AM To: AK, GWO SUPT Well Integrity Subject: RE: aio4f-004 (PBU 13-06A) PTD 1972180 Adrienne, We need to confirm the language. Do you wish to: 1. Withdraw the recent request (to amend the existing AIO 4F.004) and keep the well shut in under conditions of Administrative Approval AIO 4F.004? Or 2. Withdraw the recent request (to amend the existing AIO 4F.004) and also request to cancel the existing NO 4F.004? Cancelling the AIO 4F.004 implies the well is compliant with NO 4F and the AOGCC regulations which I dare say it isn't. My preference would be to keep the well under AIO 4F.004 (monthly reporting etc) until the well condition can be clarified. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793- 1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793- 1250 or chris.wallace@alaska.ciov. From: AK, GWO SUPT Well Integrity [mailto:AKDCWeIIlntegritvCoordinator@bp.com] Sent: Thursday, October 06, 2016 6:54 PM To: Wallace, Chris D (DOA) <chris.waIlace @alaska.gov> Cc: AK, GWO SUPT Well Integrity <AKDCWeIIlntegritvCoordinator@bp.com> Subject: RE: aio4f-004 (PBU 13-06A) PTD 1972180 Chris, While performing recent prep work for setting the tubing patch, the well began to exhibit signs of tubing x OA communication. would like to request the AA be cancelled. If you agree, we will submit a request for a new Administrative Approval once we've established two competent barriers. I'll make sure we send the associated MIT forms to the distribution list prior to submitting the request. In response to your comments and question below: The Request for Amendment should have referenced the final MIT -IA test pressure of 2258 psi, not the starting pressure of 2500 psi. I apologize for the oversight. The maximum anticipated injection pressure for water service is 2000 psi, based on data from 2004 — 2014. Please let me know if you have questions or need more information. Thanks, Adrienne McVey Well Integrity Superintendent — GWO Alaska (Alternate: Jack Lau) 0: (907) 659-5102 C: (907) 943-0296 H: 2376 Email: AKDCWeIIlntegritvCoordinator@BP.com From: Wallace, Chris D (DOA) [mailto:chris.wallace@alaska.gov] Sent: Thursday, October 06, 2016 3:21 PM To: AK, GWO SUPT Well Integrity Subject: FW: aio4f-004 (PBU 13-06A) PTD 1972180 Jack, Adrienne, We have received the request to amend this AA based on additional sundry work and test results. Please provide (to the distribution list on the AOGCC MIT form) the mentioned MIT-T completed on 8/20/16, with final pressure of 2587 psi. Please provide (to the distribution list on the AOGCC MIT form) the mentioned MITIA completed on 8/20/16 with a final pressure of 2258 psi. Please note that the 9.7% drop from the starting 2500 psi almost fails based on the 10% pressure drop rule. Please also not the final test pressure achieved of 2258 psi achieves a test pressure of 2258 and not the 2500 psi the amendment to the AA requires/requests. Please provide the TIO raw data or estimate the maximum injection pressure for this well. Thanks and Regards, Chris Wallace, Sr. Petroleum Engineer, Alaska Oil and Gas Conservation Commission, 333 West 7th Avenue, Anchorage, AK 99501, (907) 793- 1250 (phone), (907) 276-7542 (fax), chris.wallace@alaska.gov 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 Chris Wallace at 907-793- 1250 or chris.wallace@alaska.gov. by BP Exploration (Alaska) Inc. Ryan Daniel, Well Integrity Engineer Team Leader Post Office Box 196612 Anchorage, Alaska 99519-6612 September 07, 2016 OC1 0 4 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue AOGCC Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 13-06A (PTD # 1972180) Request for Amendment to Administrative Approval 4F.004 Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests an amendment to Administrative Approval (AA) Area Injection Order (AIO) 4F.004 for continued water only injection operations with a shallow packer depth into Prudhoe Bay well 13-06A. Well 13-06A was approved for continued water injections per AA NO 4F.004 on July 9, 2015 for a shallow packer depth pending successful repair per sundry # 31_ 5-264 BPXA would like to request an amendment to AIO 4F.004 to include secondary sundry repair # 316-202 and activating the contingency to set a tubing patch across the tubing perforations at —1800' MD. 13-06A had a production casing leak at 238' which was to be repaired per Sundry # 315-264 ✓ with a cement squeeze of the IA up to —1600' and by fully cementing the OA. A SCMT verified top of cement (TOC) placement after the initial IA squeeze and a WFL indicated no flow behind pipe. However, post repair, MIT -Ts conducted to confirm the success of the repair failed due to the tubing and outer annulus (OA) pressure tracking. A secondary sundry #316-202 approved a subsequent OA squeeze. An MIT -IA and MIT-T were conducted post squeez o �300 and 2750 psi respectively to confirm the success of the repair and that the tubing and production casing are competent. In addition to the passing MITs, a tubing patch will also be set across tubing perforations at —1800' MD. For continued operation of the well, the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well 13-06A is safe to operate following the successful completion and testing stated in both sundry # 315-264 and sundry # 316-202. BPXA requests amendment to NO 4F.004 for continued wa er Inlec ion operations with a shallow packer depth to include the secondary sundry repair (#316-202) and upcoming patch let - 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 Flow Station 3 Operations Team Leader Kristine Odom Ryan Daniel Prudhoe Bay Well 13-06A Technical Justification for Administrative Approval Request September 07, 2016 Well History and Status 13-06A was a WAG well prior to showing IAxOA communication in late 2013 after which it was secured with a downhole plug on 02/07/2014 and made Not Operable. A leak detect log on 01/18/2015 discovered a hole in the production casing at 238'. This leak was attempted to be repaired with a cement squeeze per sundry # 315-264. A SCMT run 10/02/2015 verified TOC placement to be at 1590' after the initial IA squeeze and a WFL run on 01/28/16 verified no flow behind pipe. However, subsequent MIT -Ts conducted to 2500 psi failed due to tubing by OA communication. A secondary sundry #316-202 was approved for an OA squeeze performed 08/06/16. Both a MIT-T and MIT -IA passed post squeeze to 2750 psi and 2500 psi respectively, confirming the success of the repair and that the tubing and production casing are competent. A patch will also be set prior to placing the well on injection. Recent Well Events: ➢ 02/07/14: MIT-T passed to 2500 psi ➢ 01/17/15: MIT-OA passed to 1200 psi ➢ 01/17/15: MIT -IA failed to 2500 psi ➢ 01/18/15: Leak detect log found IAxOA leak at 238' ➢ 10/02/15: SCMT verified TOC placement at 1590' ➢ 11/05/15: MIT -IA Passed to 2500 psi ➢ 01/28/16: WFL confirmed no flow behind pipe ➢ 03/03/16: MIT-T Passed to 2300 psi ➢ 03/16/16: MIT-T Failed at 2500 psi ➢ 06/05/16: MIT-T Failed to 2500 psi ➢ 06/07/16: MIT-T Failed to 2500 psi ➢ 08/06/16: OA squeeze performed ➢ 08/20/16: MIT-T Passed to 2750psi, MIT -IA passed to 2500 psi Barrier and Hazard Evaluation z5 51 �� I �.2 S 4 The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. A pressure test of the inner annulus and tubing were conducted to 2500 psi and 2750 psi respectively, demonstrating competent primary and secondary barriers systems. Pressure on the inner annulus will be maintained below the normal operating limit of 2000 psi when the well is on-line and a patch will be set across tubing perforations at 1800' MD. Proposed Operating and Monitoring Plan 1. Set patch across tubing perforations at 1800' MD. 2. Allow water injection only. 3. Record wellhead pressures and injection rate daily. 4. Submit a monthly report of well pressures and injection rates to the AOGCC. 5. Perform initial MIT -IA and MIT-T to 2500 psi and every 2 years thereafter. 6. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. 7 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: iim.regg(rDalaska.gov: AOGCC.Inspectors0alaska.gov: phoebe.brooks(rDalaska.gov chds.wallace(dalaska.gov $' 0 OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. Prudhoe Bay / PBU / P 08/20/16 Whitney Pettus n. 60 Min. al p 1 0/ G \ B Packer Depth Pretest Initial 15 Min. 30 Min. 45 i TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey O = Other (describe in notes) W = Water D = Differential Temperature Test Form 10-426 (Revised 11/2012) MIT PBU 13-06A (PTD# 1972180) 08-20-16.xls Form 10-426 (Revised 11/2012) MIT PBU 13-06A (PTD# 1972180) 08-20-16.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.reaaRDalaska.pov: AOGCC.Inspectors(cDalaska.aov: phoebe. brooks(cbalaska.aov chhs.wallace(cbalaska.aov OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD: Prudhoe Bav / PBU / P DATE: 08/20/16 OPERATOR REP: Whitney Pettus AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 13-06A Type Inj. I W TVD 1 8,614'ACasing 2 2,750 2,425 Interval p P.T.D. 1972180 Type test N Test psi 2153.5 P/F F Notes: MIT-T to evaluate for Administrative Approval 45 45 45 Well 13-06A Type Inj. I W I TVD 1 8,614' Tubing 2,385 2,750 2,545 2,342 Interval p P.T.D. 1972180 I Type test I N I Test psil 2153.5 Casing P/F F Notes: MIT-T to evaluate for Administrative Approval OA 45 45 45 47 Well I 13-06A I T pe In . W I TVD 1 8,614' Tubing 2,296 2,750 2,609 2,531 Interval p P.T.D. 1972180 I Type test I N I Test psi 1 2153.5 Casing I P/F F Notes: MIT-T to evaluate for Administrative Approval OA 47 �47 47 47 Well I 13-06A I Type Inj. W I TVD 1 8,614' Tubing 2,516 2,750 2,649 2,587 Interval p P.T.D. 1972180 Type test N Test psi 2153.5 Casing P/F P Notes: MIT-T to evaluate for Administrative Approval OA 47 �47-47 47 Pass per en r review, used 19.1 bbls diesel to reach test pressure, bled back 2.9 bbls Well I I Type Inj. TVD I Tubingl I I I I I I Interval P.T.D.1 I Type test I Test psi Casin P/F Notes: GA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey O = Other (describe in notes) W = Water D = Differential Temperature Test Form 10-426 (Revised 11/2012) MIT PBU 13-06A (PTD# 1972180) 08-20-16.xls 4,000 I �a Well 13-06A TIO Plot 13 06 110 p" 3i I-, 1E za X, i '-di i� i_ 2 R6 16 L, [late Stw/Erid 07/08/2013 I LP.1md ft Maw S—t. ....... . ..... C— Val.. X 05/29?2013 y 4.448 Well 13-06A Injection Plot 3. 3. 2. 2 2. 2. 2. 2, 1. 1. 1. 1. 23.OK, Z2 OM 21,000 20f00 19,000 16W0 17,000 16 CODO '5.000 14 000 13,OM 12 000 n 11,000 10,000 9.000 8,000 6f� 5.0w 4.000 3,000 2ao 1000 Daka SladTM 07AN 2013 9/aIA16 h Gdd Log Scale To ao—d Cursor Vale % 05/30/2013 Y 694 TWE , 6 X 7 CW FLS VVILLHEAD= GRAY GEN4 ACfUA10R= CAW;nm OKB. ELFV - 7v BF H.EV = ? 3OW wx Angle 0.51 ov Datm U) = low Daturn TVO = 88wssl 13, W(SG, ?2w, 1,,80, 1) - 12 34 r I i 296>f 1Minonum 10 = 3.8 13" @ I o3ft.-, 1 4-112" HES X NIPPLE I TOP OF CHANT 103W 9-518'CSG,47* L-80,0=8681' PFWORATM SLOAARY FU LOG: SHOS ON Oill IM ANGLE A AT TOP PEW: 10"@ 10612 We %fef to Production DD for hotoricM pert data SZE SK 114FE1VAL Opnisqz SHOT soz 3,3W 6 10612-10668 0 02104= 3.3(8' 6 1 10682- 0707 � 0 =04/00 3,3W 4 10745-10759 0 Ozilm 3.3f8" 4 10774 - 10820 0 0011r98 SAFETY HO'feSi WS RrADINGS AVERAGE 12$ ppo WHEN ON Mi. WELL JWQLWMS A W3V WHEN ON #ail! � �. L=VMNDOW $958' - $9fi8' � 1 110277 H4,V2-CMTRETAt4ERWSLOWSLV(O0115i15) ULM* 7'X 4-112" BAKER S-3 PKA, ii7i- I' LW. 2", L 80. 0 0 3413 bipt. D - 6.276' PATE REV BY COMUR4m, GATE REV BY cohokwm owl em I 1i ORKANA.L COMPLETION 12M7115 SJWAV OA CFUROM (I 1114f 15) 0211 IffiC WOWJNER 12M415 SJWJW FISR MLLED ZX CBPS DH 0311MI! SI& MD FML OYDN16 mmAo SET 4 irr w PLuc (ommi s) OW 1102 RWTP CORRECTIONS OY161161 RWINU TREEUO(OWY16) 10128r15jNXWTLH EjKRCW9FNRTAG (1Oil5ol5) FISR 2 CBFS WLEDOH (11113115) PRJFA-M BAY UNT WELL 13-OSA FEFWTW 197-2180 AR Na' 50 029 2OW 01 Sty 13, TI ON, R14E. 164Y FEL & SV FV4L 12 RECEIVED by BP Exploration (Alaska) Inc. MAY 6 2011] Douglas A. Cismoski, P.E., BPXA Wells Operations Manager Post Office Box 196612r1(�('� Anchorage, Alaska 99519-661 `L O VV VV April 25, 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 14-27 (PTD # 1831700) Request for Administrative Approval to Continue WAG Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue WAG injection operations into Prudhoe Bay well 14-27. 14-27 previously had a production casing leak at 5714' and a tubing leak at 8170' which was repaired with a cement squeeze per Sundry # 315-536 on 12/9/15. The annulus cement top was logged at 3064' on 01/25/16. A passing MIT-T to 2850 psi was conducted on 02/24/2016 and a passing MIT -IA to 4000 psi was conducted on 12/14/2015, indicating the success of the repair and that the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well 14-27 is safe to operate as stated above and requests administrative approval for continued WAG injection operations. If you have any questions, please call me at 564-4303 or Adrian McVey/ Jack Lau at 659-5102. Sincerely, Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski McVey/ Lau Flow Station 3 Operations Team Leader Paulina Meixueiro Ryan Daniel Prudhoe Bay Well 14-27 Technical Justification for Administrative Approval Request April 25, 2016 Well History and Status Prudhoe Bay injection well 14-27 (PTD # 1831700) had a production casing leak at 5714' and a tubing leak at 8170' which was repaired with a cement squeeze per Sundry # 315-536 on 12/9/15. The post squeeze MIT -IA and MIT-T passed demonstrating competent tubing, production casing and cement. A neutron water flow log with shut in temperature warmback passes was conducted on 04/23/16 and showed there was no upward movement of fluid in the IA between the tubing punch holes and the PC leak. MI benefits to producers in the 14-27 pattern over PWI only assuming one bulb per year for the next four years are: Year 1 - 300bopd Year 2 - 210bopd Year 3 - 147bopd Year 4 - 103bopd Recent Well Events: ➢ 12/09/2015: IA cement squeeze completed ➢ 12/14/2015: MIT -IA passed to 4000 psi ➢ 01 /25/2016: IA cement top logged at 3064' ➢ 02/24/2016: MIT-T passed to 2850 psi ➢ 04/23/2016: Neutron water flow log and temperature warmback passes show no flow behind pipe. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing, associated hardware and cement. A passing pressure test of the inner annulus to 4000 psi and the tubing to 2850 psi, demonstrates a competent primary and secondary barriers 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. Record wellhead pressures and injection rate daily. 2. Submit a monthly report of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA and MIT-T to maximum injection pressure. 4. Maintain IA pressure below 2000 psi normal operating limit. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well 14-27 TIO Plot 14-27 TIO Plot -0— Tbg ,--a— LA A OA OOA OOOA On Date Stait/End 04/25/Ml 5 4/25/2016 CRjoa�d TIO GO Save to C pbo iard Cursor Value X 04/27/2015 y 5.021 Jv- Well 14-27 Injection Plot 5 Z�- S 1 Ri 5 - Date Start/End 04125/2015 4/25/M 16 �aPa Li Inj God Log Scale TOE Cursor Value WHIP S111 X 06/18/2015 R�l y 1,865 ml GI O#W On 14-27 Wellbore Schematic TFEE- FW120L ❑ATE FWV BY XWEl s DATE REV BY OOM ENM 17 ISM MR" 04'"AL COMPLETION Ot/25/M6 FOAO IFEF OO (01111116) MAW" MES RNIo 01125/16 3l,MU M L PLUGS W (01JM16) 11/25/13 PJC KS Pf0iASSY CL i10N' --- - — 11117115 TM-W PULL® PKR ASSYISET FISH 12103l15 MGBI,AV CBPrW PU GYpUFAT 11211VI51 JTWJ/[1 jCW SOZ (12109H5) PF'WDHDE BAY UMr WELL. 14 27 PSW No: 1831700 AM W: 50.029-21046-00 SEC 9, T10N, R14F- 2459' FFC 3 796' FEL BP Exploration (Alaska) 11 bp BP Exploration (Alaska) Inc. RECEIVED Douglas A. Cismoski, P.E., BPXA Wells Intervention Manager APR 0 6 2016 Post Office Box 196612 Anchorage, Alaska 99519-6612 gOGCC 0 April 5, 2016 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay well X-33 (PTD # 1961440) 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-33. Well X-33 began exhibiting manageable inner annulus repressurization of —5 psi/day while on water injection at the beginning of September 2015. A pressure test of the inner annulus passed to 2500 psi on 09/19/2015, indicating the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well X-33 is safe to operate as stated above and requests administrative approval for continued water injection operations, managing the IA repressurization with periodic annular bleeds. If you have any questions, please call me at 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. Sincerely, Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks GC3 Operations Team Leader Wade Boman Ryan Daniel Prudhoe Bay Well X-33 Technical Justification for Administrative Approval Request April 5, 2014 Well History and Status Prudhoe Bay well X-33 (PTD #1961440) exhibits manageable inner annulus repressurization indicated by wellhead pressure trends on the TIO plot. A MIT -IA to 4000 psi on 09/13/2015 and 2500psi on 09/19/2015 passed indicating competent tubing and production casing. The recorded IA build-up rate while the well was on water injection between 12/11/2015 and 2/1/2016 was -5 psi/day. X-33 will be managed on water injection only with periodic IA bleeds if necessary. Recent Well Events: ➢ 09/19/2015: AOGCC MIT -IA passed to 2500 psi ➢ 09/13/2015: MIT -IA passed to 4000 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing and associated hardware. An AOGCC witnessed pressure test of the inner annulus passed to 2500 psi, demonstrating competent primary and secondary barriers 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. L5 Lo o i °` 0> a w BWPD I MCFPD M CO I-- tlo R dlHAA TRH = 'ACTUATOR 4' CtW ATOR � BAKER X-33 KB BLEV = 68.10' BF. G-Ev - 29Ya t<OP __ 123T klax Angle - 91' Q 131W Datum ND = 12336 DahmTVO= 88WSS Minimum 10 =1275" 8@ 12262' 4412" X 2-716" X NIP REDUCER 14-1/2-13G, 12.SY, L-80, .0152 bpl, D = 3.958- i--i 1227W i PERFORATION SUMMARY FIEF LOG DRt.LB2"i DEPTH V16 TE L ANGLE AT TOP PEW: 89' @ 12900' Note. Refer to Ptoduction DB for historical perf data SQE SPF 94FIRVAL Opn/Sgz SHOT SOZ 2-314" 4 12900 - 13000 O 02/10V97 2-3/4' 4 13320- 13350 O 11/14/96 2-3/4" 4 13750 - 13850 O 02/1097 2-314' 4 14370 - 14510 C 04/02/98 4-1/2' LW SAFETY NOTES: HZS IMCINGS AVERAGE 125 ppm WHEN ON MI — WELL RHAWES A SSSV WHEN ON MI — WELL ANGLE> 70' @ 14555' *'"T BG LEAK IDB111FIED@ 1197V (06111UO7) — 218V 4-12-FESHXOSLVN,9)=3.813- OAS LIFT W hEW .S ST ND TVD I DlV TYPE VLv LATCH PORT DATE 5 3015 27471 49 KWC 2LS DMY NT 0 11/13/96 4 6337 4905 47 IB( 2LS DMY NT 0 11/13196 3 8954 6648 48 IBG-2LS DMY HT 0 11/13/96 2 10774 783 551 IqW 2&S DMY Kr 0 11/13M6 1 12014 8654 50 193O-2LS DMY NT 0 11113tg6 119150' 41/7 BKR PATCH SET. D-2.45- 1220T 4-1/2' FES X NP, D = 3.813- 1221V H7-x 4-1/r BKRS-3 PKR D=3.875- 12242' 4-1l2- HES X NP, 1D= 3.$13' lUiFj 4-12- X2-318'XiPRMC ,9=1.875'(7111/07) 4 *&-W w_�n-uccYtiaon-�»n- 12266' 7- X 5- ZXP PKR & FW FNGR wREBACKSLV, 1)=4.563' 12276- 4Al2- WLEG, D = 3956- 1227T HELMDTTLOGGED OW15198 4 MCC• !C-Y A_1/I-Yn n=2 orir F 14518' 1462Z DATE REV BY OONNENTS GATE FIEV BY COILBrBan 11M4/96 CHR OFOG H014Z COMPLETION ll/W14 PJC NPRMU(XRCJORRB�TION 05/18107 SRBIPJC XN PAP FULLED TBG LEAK 1121114 TJW PJC SSSV NPCOIECTFON 0722f07 SVVGPJC SET XN NP R D & XX PLUG 08107107 GJBISV BAKER PATCH SET (7/30/07) 09/18/07 BSE7PJC FI-LL XX PLUG/ "YO SLV N 02/16/11 MEVAD ADDF3DSSSV SAFETY NOTE PRUDHOE BAY LHT VWBL: X-33 Pamr w:1961440 AR N1: 50-029-22699-70 Sec. 5. T10N. R14E BP 6Lplwatkm (Akska) 10 BP Exploration (Alaska) Inc. Douglas A. Cismoski, P.E., BPXA Wells Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 December 1, 2015 by RECEIVED DEC 02 2015 0 AOGCC Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 13-17 (PTD # 1820260) Request for Administrative Approval to Continue WAG Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval to continue WAG injection operations into Prudhoe Bay well 13-17. The well previously had a production casing leak at 9467' which was repaired with a cement squeeze per Sundry # 315-108 on 06/23/2015. The annulus cement top was logged at 3220' on 06/28/2015. A passing MIT-T to 4000 psi was conducted on 08/19/2015 and a passing MIT -IA to 4000 psi was conducted on 10/3/2015, indicating the success of the repair and that the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well 13-17 is safe to operate as stated above and requests administrative approval for continued WAG injection operations. If you have any questions, please call me at 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. Sincerely, Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks Flow Station 3 Operations Team Leader Irwin Chou Ryan Daniel Prudhoe Bay Well 13-17 Technical Justification for Administrative Approval Request December 1, 2015 Well History and Status Prudhoe Bay injection well 13-17 (PTD # 1820260) had a production casing leak at 9467' which was repaired with a cement squeeze per Sundry # 315-108 on 06/23/2015. The post squeeze MIT -IA and MIT-T passed demonstrating competent tubing, production casing and cement. A neutron water flow log with shut in temperature warmback passes was conducted on 11/30/2015 and showed there was no upward movement of fluid in the IA between the tubing punch holes and the PC leak. MI benefits to producers in the 13-17 pattern over PWI only assuming one bulb per year for the next four years are: year 1: 125 bopd, year 2: 88 bopd, year 161 bopd, year 4: 42 bopd. Recent Well Events: ➢ 06/19/2015: IA cement squeeze completed ➢ 06/23/2015: MIT -IA passed to 2500 psi ➢ 06/28/2015: IA cement top logged at 3220' ➢ 08/19/2015: MIT-T passed to 4000 psi ➢ 10/03/2015: MIT -IA passed to 4000 psi ➢ 11/30/2015: Neutron water flow log and temperature warmback passes show no flow behind pipe. Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing and production casing, associated hardware and cement. A pressure test of the inner annulus and tubing passed to 4000 psi, demonstrating competent primary and secondary barriers 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. Record wellhead pressures and injection rate daily. 2. Submit a monthly report of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA and MIT-T to maximum injection pressure. 4. Maintain IA pressure below 2000 psi normal operating limit. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well 13-17 TIO Plot 13-17 TIO Plot 4.000 3,000 2. f Tbg —�— IA —� OA OOA —+► — OOOA OR 1.000 12101114 C1r01115 02101115 03AW15 04AW15 05/05/15 06t45115 07,%115 M06i15 09A)6115 10107115 11107115 Date Start/End 12/1/2014 12/1/2015 Reload Plot TIO God Ito _I Cursor Value X 11/14/2014 Y 3,808 Well 13-17 Injection Plot 3.2M 3,000 2.800 ZGDO 2.400 2,200 2,ODO 1$0D c� 1,600 1,400 1,200 1,000 80D 600 400 200 12� 1;11 115 15 &:34 15 _ = ; - 0605J15 07J46J15 08+46J15 09IM15 10J07115 11/07115 50D 48D 460 440 420 400 3K, 360 340 320 300 ao 28D v 260 a 240 c� 220 Q 200 180 160 140 120 11000 30 60 Dry 20 WHIP SSJAJ r q roil OtherGVl �� '�yr On Date Start/End 12/1/2014 12/1/2015 Reload Plot Inj Grid Log Scale To Clipboard Cursor Value X 04/03/2015 Y 2.237 13-17 Wellbore Schematic Try 'I 3 -'17 WEl'iFfAD- f#F SAPEIYNOIUS "'M2SRfAIIIN-ibAVMAGE125 ACTLIA TOR = - BA�t C' DPm WHENONMi "' tNIH l I�LQUI�S A SSSW WHEN OKB ELFV = aT -�—�•r or1 Mr �- tw t3,l V = rya KOP- 300(Y COtDL.ICTOR. — Wx Arqk - 57` 0 6975' Datum WD = 1119T 17 . Oatunt TVQ- t1600' SS 1 }3ra' csG, I 30 BIC, U -- 12 341' T )C IN A (06t1905; �� J 9-518' CSG, 47N, L-80 XO TO SCK)4" BLM 91l94' 1Lsn� rt�Nca11oa/1su1a} � 1�70' - 10075' W-M Z a 4SPF 104t2?J151 10216' - 10220' M167IM N = 3.725" @ 14309 4-112" HES XN NIPPLE TOPOF 4-1mr Lha� -410309 4-V2- TBG,12.6#, L-80, A152 Lwf, D - 3.958-I 10347' TC^P OF 7" LNR as/a• csc, a70, s0a9s BIm. n = a a61 • H 108W PCIT-ORAT)ON sr UVARY REF LOG: BHCS ON (I4,413V ANGLE AT TOP PEW: 38' 01109Y Note: War to FhWucbon DB'or historical pert data SIZE SFF RJERVAL Op-VSgz SHOT SQ2 2-1/2' 4 11050 - 11105 S. [F8104182 09f22101 3-3/8' 4 11054 - 11084 Q 06i2QM 3-3/8' 4 11074 - 11084 O OOMM 3-M' 4 11094 - 11104 0 06r29103 3 WIF 4 M 14 - 11114 U tNif2f} w 2 112' 4 11129 11 M S 136104 82 09/22/01" 3-318' 4 11 M - 11142 O 06fi9/03 3-3/8" 4 11146 - 11156 Q 0629M 3 318' 4 11162 11182 O M29M f-U7' 4 11166 - 1118a S MUM 0902101 3-3/8' 4 1 / 188 - 11190 O (029M 3 3/8' 4 11202 11220 O r06, SM 3-1/7' 4 117M - 11777 S f08t0 w 0907101 3-318' 4 11224 - 11234 O 06.28M i- Wr 4 1174A - 112R4 r) (Mit7flM 3-3f8" 4 11370- 11410 C 01r191D? LNF7 12.BK, L-60 6TC, .0152 W, ID= 3.958' NR. 996. 1-M BUfT. .D17I Iwf. U=6.194" "u 114TY 11561' 2238' H4-VTCAMODBAL-OS53VI*D=3.612" 1 103p9' 4-112' fiES XN 11 F 9-5M' X 7' BKR ZXP FKR wfFEBACK SLY, D= 6.263' 10323 i& S/t7' x 7• f3102 HKC WOO IL) = 1033T a 25' SFAt 50FIr FXT, ID - 4 A 103W i-j7- X 4- Vr X0, 0 = 3.958' 11369, J - ubp f wi,lstTs; I PMEHHOE BAY LM' VAIL. 13-17 FT FMT No' r187076(1 AH Nu- 50-029-20718-00 S {,14, TiDN, R14F, 7703' FN 8 1634' FR DATE REV BY COMENM DATE , 9i BY COAa1 mwm 04114182 0CWB.5 ORKWAAL COMPLt-YiCM1 UP15115 LAND CMTW R FIETAW63(06118-1�15) 12f 2510'1 0616 ONO 0711ZI5 P+1iKM PA L E11 C WMW-TAM:R & C111:S 04715115 1M1F' PULLED F'101 SFT (3) CY3PlS (041T0 W1?111 ) 0&31115 XG J SET XXN R-UG (08/19(15) 0417tY15 P, 10t{t!! 1!r J RI 1 Hi XSfN Pt Ur (10707115) C7Ai'2N15 P FUGPLR�IGFi �......T.._n� THG PU,01 --------- _.,�.�.. f BP Exploration tAAaaRa► j05"10/15 TJM Wallace, Chris D (DOA) From: AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com> Sent: Saturday, December 05, 2015 5:19 AM To: Wallace, Chris D (DOA) Cc: AK, D&C Well Integrity Coordinator Subject: RE: UPDATE December 01, 2015: UNDER EVALUATION: Injector 13-17 (PTD #1820260) Well Approved for Continued Injection Attachments: MIT PBU 13-17 NON WITNESSED Aug -Oct 2015 MITs.xls �Q �}-, 00 Chris, Please see the attached MIT form for Injector 13-17 (PTD #1820260) for 10/3/2015 MIT -IA and 8/19/2015 MIT-T results. Please let me know if you have any other questions, comments, or concerns. Thank you, Whitney Pettus (Alternate: Kevin Parks) /B'P��Allastka - Well Integrity Coordinator UYY WIC Office: 907.659.5102 WIC Email: AKDCWelllntegritvCoordinator@BP.com From: Wallace, Chris D (DOA)[mailto:chris.wallace@alaska.gov] Sent: Friday, December 04, 2015 8:41 AM To: AK, D&C Well Integrity Coordinator Subject: RE: UPDATE December 01, 2015: UNDER EVALUATION: Injector 13-17 (PTD #1820260) Well Approved for Continued Injection Whitney, Please send/resend the 10/3/2015 4000 psi MITIA and 8/19/2015 MITT referenced in the recently received AA. Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1250 (phone) (907) 276-7542 (fax) chris.wallace@alaska.gov 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 Chris Wallace at 907-793-1250 or chris.wallace@alaska.aov. From: AK, D&C Well Integrity Coordinator[mailto:AKDCWellIntegrityCoordinator@bp.com] Sent: Tuesday, December 01, 2015 7:48 PM To: AK, OPS FS3 OSM; AK, OPS FS3 Field OTL; AK, OPS FS3 Facility OTL; AK, OPS FS3 DS Ops Lead; AK, D&C Well Services Operations Superintendent; AK, D&C Wireline Operations Superintendent; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; AK, OPS PCC EOC TL; AK, OPS PCC Ops Lead; G GPB FS3 Drillsites; Chou, Irwin; 'chris.wallace@alaska.gov' Cc: AK, D&C Well Integrity Coordinator; AK, D&C Projects Well Integrity Engineer; AK, D&C DHD Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Morrison, Spencer; Sayers, Jessica; Dickerman, Eric; Regg, James B (DOA); Pettus, Whitney Subject: UPDATE December 01, 2015: UNDER EVALUATION: Injector 13-17 (PTD #1820260) Well Approved for Continued Injection All, Injector 13-17 (PTD #1820260) can remain in service following the water flow log performed on December 01, 2015. The well will remain Under Evaluation until an Administrative Approval (AA) can be approved for continued injection post annulus repair. Plan Forward: 1. Operations: Keep on injection as needed Downhole Diagnostics: Perform AOGCC MIT -IA as required following AA approval 3. Well Integrity Engineer: Additional diagnostics as needed Please call with any questions or concerns. Thank you, Whitney Pettus (Alternate: Merin Parks) BP Alaska - Well Integrity Coordinator WIC Office: 907.659.5102 WIC Email: AKDCWelllntesrityCoordinator@BP.com From: AK, D&C Well Integrity Coordinator Sent: Saturday, November 28, 2015 8:05 AM To: AK, OPS FS3 OSM; AK, OPS FS3 Field OTL; AK, OPS FS3 Facility OTL; AK, OPS FS3 DS Ops Lead; AK, D&C Well Services Operations Superintendent; AK, D&C Wireline Operations Superintendent; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; AK, OPS PCC EOC TL; AK, OPS PCC Ops Lead; G GPB FS3 Drillsites; Chou, Irwin; 'chris.wallace@alaska.gov' Cc: AK, D&C Well Integrity Coordinator; AK, D&C DHD Well Integrity Engineer; AK, D&C Projects Well Integrity Engineer; AK, OPS FF Well Ops Comp Rep; Sternicki, Oliver R; Pettus, Whitney; 'Regg, James B (DOA)'; Sayers, Jessica; Dickerman, Eric; AK, D&C Wells Eline Coordinator; Do, Matthew; Broussard, Mike G Subject: UNDER EVALUATION: Injector 13-17 (PTD #1820260) Place on Injection for Compliance Log All, Injector 13-17 (PTD #1820260) is a WAG injector with a known PC leak at 9647' MD that was mitigated by an inner annulus cement squeeze on June 19, 2015. A subsequently passing MIT -IA to 4000 psi was performed post squeeze on October 03, 2015 demonstrating two competent barriers to formation. In order to pursue administrative approval (AA) for continued operations of the well, an initial water flow log will be run in order to verify that there is no significant flow behind pipe. At this time, the well is reclassified as Under Evaluation to facilitate compliance diagnostics. Please use caution when bringing the well online as the annuli are fluid packed. Plan Forward: 1. Operations: Place well on injection 2. Electric Line: Once thermally stable, perform water flow log 3. Well Integrity Engineer: Additional diagnostics as needed Please call with any questions or concerns. Thank you, Whitney Pettus (Alternate: Kevin Parks) BP Alaska - Well Integrity Coordinator V%/ WIC Office: 907.659.5102 WIC Email: AKDCWellintegritVCoordinator@BP.com From: AK, D&C Well Integrity Coordinator Sent: Wednesday, August 31, 2011 1:59 PM To: 'Maunder, Thomas E (DOA)'; 'Regg, James B (DOA)'; 'Schwartz, Guy L (DOA)'; AK, OPS FS3 OSM; AK, OPS FS3 DS Ops Lead; AK, OPS FS3 DS Operators; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; Cismoski, Doug A; Daniel, Ryan; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; AK, OPS PCC EOC TL; Catron, Garry R (SAIC) Cc: AK, D&C Well Integrity Coordinator; Clingingsmith, Mike J (Swift); Arend, Jon (NORTHERN SOLUTIONS LLC) Subject: NOT OPERABLE: Injector 13-17 (PTD #1820260) Well Due for AOGCC 4 year MIT -IA, Pending Flowline Repairs All, WAG injector 13-17 (PTD #1820260) will be due for a 4 year compliance AOGCC MIT -IA on 09/03/2011. Currently the well has been shut-in since May, 2011 while repairs to the flow line are being performed. No tentative date has given for resumption of injection into the well. The well is reclassified as Not Operable until such time as the flowline is repaired. The well will be included on the quarterly AOGCC Not Operable Injector report. A TIO and injection plot has been included for reference. Please call if you have any questions. Thank you, Gerald Murphy (alt. Mehreen Vazir) Well Integrity Coordinator Office (907) 659-5102 Cell (907) 752-0755 Pager (907) 659-5100 Ext. 1154 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submitto: AOGCC.Insoectors(a)_alaska.gov; phoebe. brooks(a)alaska.gov chds.wallace(a)alaska.aov OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD: Prudhoe / GPB / 13 DATE: 08/19/15 OPERATOR REP: Whitney Pettus AOGCC REP: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 13-17 I Type In'. N TVD 8,217' Tubin 1,991 4,060 4,036 4,023 1 Interval O P.T.D. 1820260 I Type test I P Test psi 2054.25 Casin 1,171 1,211 1,170 1,140 P/F I P Notes: Non witnessed SI MIT-T post IA cement OA 4 4 4 14 Well I Type In'. I I TVD Tubing Interval P.T.D. I Type test I 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 I Casing P/F Notes: OA 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 Type In'. I TVD I Tubing Interval P.T.D. I Type test 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 O = Other (describe in notes) Form 10-426 (Revised 11 /2012) MIT PBU 13-17 NON WITNESSED Aug_Oct 2015 MITs.xls STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: iim.regg@alaska.gov; AOGCC.InsoectorsCa�alaska.gov; phoebe. brooks@alaska.gov chris.wallace(cbalaska.gov OPERATOR: BP Exploration (Alaska), Inc. FIELD / UNIT / PAD DATE: OPERATOR REP AOGCC REP: Prudhoe / GPB / 13 10/03/15 Whitney Pettus Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 13-17 Type In'. I N TVD 8,217' Tubing 112 309 319 323 Interval O P.T.D. 1820260 I Type test I est psi 2054.25 Casing 192 4,000 3,781 3,674 P/FJ P Notes: Non witnessed SI MIT -IA post IA cement OA 0 1 2 2 Well 13-17 I Type In . I N I TVD 1 8,217' Tubing 325 364 366 366 1 Interval O P.T.D. 1820260 1 Type test I P I Test psi 2054.25 Casing 3,523 4,300 4,160 4,073 P/F P Notes: Non witnessed SI MIT -IA post IA cement OA 2 2 2 2 Well 1 13-17 1 Type In'. N TVD 8,217' Tubing 364 379 378 376 375 372 Interval O P.T.D. 1 1820260 1 Type test P Test psi 2054.25 Casing 4,011 4,300 4,200 4,123 4,059 4,000 P/F P Notes: Non witnessed SI MIT -IA post IA cement OA 2 2 2 2 2 2 Well I Type In'. I I TVD I Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well I Type In'. I I TVD Tubing Interval P.T.D. Type test Test psi Casin P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey O = Other (describe in notes) W = Water D = Differential Temperature Test BP Exploration (Alaska) Inc. Douglas A. Cismoski, P.E., BPXA Wells Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 September 10, 2015 by RECEIVED SEP 21 2015 0 AOGCC Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay well S-25A (PTD # 1982140) 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-25A. Well S-25A began exhibiting manageable inner annulus repressurization of -101 psi/day while on gas injection at the beginning of May 2015. A pressure test of the inner annulus passed to 2500 psi on 5/12/2015, indicating the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well S-25A is safe to operate as stated above and requests administrative approval for continued water injection operations, managing the IA repressurization with periodic annular bleeds. If you have any questions, please call me at 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. Sincerely, -: �)' , /,//- d� � 4 - 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 Matthew Bergene Ryan Daniel Prudhoe Bay Well S-25A Technical Justification for Administrative Approval Request September 10, 2015 Well History and Status Prudhoe Bay well S-25A (PTD #1982140) exhibits manageable inner annulus repressurization indicated by wellhead pressure trends on the TIO plot. A MIT -IA to 2500 psi passed on 05/15/2015 indicating competent tubing and production casing. The recorded IA build up rate while the well was on gas injection between 05/05/2015 and 05/11/2015 was -101 psi/day and will be managed on water injection only with periodic IA bleeds if necessary. Recent Well Events: ➢ 02/04/2015: MIT -IA passed to 4000 psi ➢ 02/13/2015: AOGCC MIT -IA passed to 2300 psi ➢ 05/11/2015: 101 psi/day IA build up rate while on MI ➢ 05/12/2015: MIT -IA passed to 2500 psi ➢ 05/15/2015: PPPOT-T passed to 5000 psi ➢ 06/18/2015: Acoustic LDL- No leaks detected 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 barriers systems. Pressure on the inner annulus is maintained below the normal operating limit of 2500 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. 4,000 3,000 2,000 FYY Well S-25A TIO Plot Owe Start/End S-25TIO mat 09/10/2014 9/10/2015 Reload Plot �:..; TIO Gnd 09/10/14 11111t14 11r11/14 12/12d14 01f12:'15 02112J15 0311505 0V15i15 05/1&15 06105 07117115 0&+17,11, —0— Tbg f W —a - CA - +- OOA - OOOA On Save to aip oard Cursor Value X 08/19/2014 Y 4,901 3,6 3,400 3,200 3,000 2,800 2,600 2,400 2,200 ZOO 1,304 1,600 1,400 1,200 1,000 300 6wx, 4 2CC, 0T1014 10111114 11111114 Well S-25A Injection Plot 0115115 0411515 050615 06t16.115 07117115 03e17115 Date Start/End 9/10/2014 3.f0 9/10/2015 7,500Reload Wat TW Li lnj Grid 6.500 Log Scale 6.0t0 C4pboard 5,50DTo Cursor Value 5,C}0 GD - WHIP X 11/27/2014 4.0 0 ` 5tiri Y 3.050 4,ODD MI 3,500 GO*M - 3,000 On 2,5N 2,OM 1,500 1,000 50D TREE = 4- it 16" cave VJRLFEAD= FMC ACTUATOR = OTIS OKB. E LFV = 6539 BF. B_EV = 3619 KOP = 5000" M?x Angle = 92 @ 109W Datum MD = 9241' DatumTVD= 88m, SS', 13-318^ CSC, 68N, L-80 STRS, D = 12.415" 1-i 2674• l Minimum 10 = 2.37*@ 8923' 3-314" X 2-7/8" LNR XO 112 TBG, 12.6M. L-80, TC-11. I { 8891` 0152 W, D 3,958" 1 TOP Qi 2-7JB" LNR D 2.37" 89Q3' -V2' TBG, 12.68, L-BQ .0152 6pf, D = 3.956' -I 8974' I9 516' CSC 47N. NT-605. NSCC. D , 8.661' 1 9140' [7'WIP5T0CKw1RATAG@9171' 9182' 7' LNR, 28A, L i T&i_. 39,3 Dpf, 10 6 278" 4,-4-i "J4-QM WN St,#vFN1FtY REF LOG: BAKER MAORE5UWriY ONM11J98 ANGLE AT TOP FEW 86" @ 105W Note. Refer to Production DB for Frstorical pert data SQE SPFJ INTERVAL OpntSgz' SHDT SOZ 2" 6 105DO - 1053D O VJ03115 Y 6 10990- 11020 0 d02103J15 2 6 11920 - 11050 O 2" 4 11364 - 11434 IOM2/15 O 11124/98 f •� �� SAFETY NOTE. H2S READINGS AVERAGE 126 ppm W►1H ON 1Jr *'" WELL REOt.11RES A SSSV WHEN ON MI -PORTIONS OF THE WELL FLOWLI FARE 3" 3 SUBJECT TO EROSION. GC SHOULD BE NOT1Rm OF ANY WELL OPERATIONS THAT COULD MCREASE THE FLOW OF FROWN RATES •^^Wa_L ANGLE> 70" @ 9350" *' 211 T _l- (4 112" HFS k NP, p 3 813" GAS LIFT MA NDRRaS ST MD I TVD OEV TYPE VLV��FC42f I DMIt 1 3795 3795 0 LUG OMY RK 0 f 12113t0 87g4• 4_ 112" HF_SX 0F, D= 3-813" 882T - 9- 5/6' X 4 112' BKR 5-3 PKR, D = 3.670' { 8851'—�-{a-1rz- r ics x rp. D= a.a1a• � 8872" i 14 112' 1 XN N9', D " 3 725" 4804' O-5/8" X 4- Ir_- OM IWl, D - 9 99- 8891 4 1 YI' MULE SHIDE D = 3.956 t 8916• I-{ 3A314" BKR I NR OFR OY St V, 91= 3AG" 8923' 3-'1ra' x ym X0, 0 ^ 1 t" I 8940• 4-112" PARKE3R SWS W. D = 3 Ei3" 8J61• I I4-112" OTS XN NP, D= 3.725" BEHIND 8974' 4-112' WLEG, D= 3.958" CT L N#U _ 8960'..__I-{ELAN T-T LOGG� 11 09,90 7- I&L OUT 44 4DOW (S-25A) 9162 9167' 2-710' LPR, 6.10p, L-d0 STL, 11554' 0058 bpf, D 2 441 • } DATE REV BY CJOHkBRS LtATE ? RF/ BY _ COWNTS� 08M7190 HF 'ORIGINAL COMPLETION 011/9/12 P ADDFDHI2S SAFETY NDTE 1124f98 CTD SIOETRACK 06/24/14 JKU UMATED WBS FER TALLER 1120106 O 011031151BLS1 P ADPERFS (02102 - 02iO3J15) 12113/06 P DWG DRAFT C014ECTKM 07110l15 J W SET PX PLUG (06117115) 12/17106 DAV1P GLV aO (12113106) 09109115`i BF1JMD PULLED PX PLUG (09MVI5) 02115J 11 ME11JWD s AMED SSSV SAFETY NOTE P8810 (CBP) H 11487' PRLCHOE BAY LMT VALL_ S-25A rtFMT Np: 1982140 AR No: 50-029.22077-01 SEE 35, T1214 R12E, 163T F1t 8 112(Y FVIL IP Expbraficm (Alaska) BP Exploration (Alaska) Inc. RECEIVED # `�re E by Clint J. Spence, BPXA Wells Interventions ETL Post Office Box 196612 J U L 0 2 2015 Anchorage, Alaska 99519-6612 ('��"'+ ��t�VV 0 July 1, 2015 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 13-06 (PTD # 1972180) 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 13-06. 13-06 currently has a production casing leak at 238' which will be repaired per Sundry # 315-264 with a cement squeeze of the IA up to —1600' and fully cementing the OA. A SCMT will verify cement placement after the initial IA squeeze. An MIT -IA and MIT-T will be conducted to 2500 psi to confirm the success of the repair and that the tubing and production casing are competent. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well 13-06 will be safe to operate pending the successful completion of the planned work and testing stated in Sundry # 315-264 and requests administrative approval for continued water injection operations. If you have any questions, please call me at 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. S inperel , 7J 4i�A�� Clint J. Spence BPXA Wells Interventions ETL Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks Flow Station 3 Operations Team Leader Irwin Chou Ryan Daniel Prudhoe Bay Well 13-06 Technical Justification for Administrative Approval Request July 1, 2015 Well History and Status 13-06 was a WAG well prior to showing IAxOA communication in late 2013 after which it was secured with a downhole plug on 02/07/2014 and made Not Operable. A leak detect log on 01/18/2015 discovered a hole in the production casing at 238'. This leak will be repaired with a cement squeeze per Sundry # 315-264. A SCMT will verify cement placement after the initial IA squeeze. A MIT -IA and MIT-T will be conducted to 2500 psi to confirm the success of the repair and that the tubing and production casing are competent. Recent Well Events: ➢ 02/07/2014: MIT-T passed to 2500 psi ➢ 01/17/2015: MIT-OA passed to 1200 psi 01/17/2015: MIT -IA failed to 2500 psi ➢ 01/18/2015: Leak detect log found IAxOA leak at 238' 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 and tubing will be conducted to 2500 psi demonstrating competent primary and secondary barriers 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. Initial cement evaluation log to show IA isolation across the cemented interval and the top of cement. 2. Record wellhead pressures and injection rate daily. 3. Submit a monthly report of well pressures and injection rates to the AOGCC. 4. Perform initial MIT -IA and MIT-T to 2500 psi and every 2 years thereafter. 5. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well 13-06 TIO Plot 13-06 T 10 Rot - a Tbg ! IA A 0.4 OOA *- OOOA On Date Start: End 07l01i2013 711I2015 Reload Plot TIO Grid Save to 00board Cursor Value X 07 16,2013 Y 4.102 Well 13-06 Injection Plot — WHIP S1'r — M: GI — Other Or= Date Start; End g'/01:ZC13 7:'1i2415 Road Plot In Gnd Log Scale To Clipboard Cursor Value X 11/06/2015 Y 3.435 Current 13-06 Well Schematic 1 F4E - ,VL , ""'4 VM -HEAD GFA" Ac",TOR- 0-as OLC. 13Fd _ 79 Of UA V - 7 KUf' 3Jge Max Angle = 51' @ 513G EvIt.m ku = 10F.'Xi'. Uat4m IVU- BE1CX7 SS 13 IV CSC, T-14 1 90, ID " 12 347- Minimum ID = 3.813- L 1037T 4-1/2- HES X NIPPLE A 112" IH(: I ftr, I " 0 332 epl, U = 4 a92- {. GG84' I[.11' (N 4 1f.'- IW. ! I 66M. 677Z 1 Uf' OF ckmnfN I I Ii ///�� SA("FTY NOTTS f(?S REAMMI AVFRAC# 173 pprn 13-0 (WHEN CM UL WELL REQLNRES A SSSV WHEN ON III '1 ?iv-- 1--I 5 t'Z• cxmK-BAL-0NP n - 4 552" 9')18'L".(.*,4/4',l W,1) 8tl81".I { 10762' t1YV VYVYY Vv l 4 12' TOG; 12 SI! L. B0, 0 0152 hpl U - 3 951r 1G388' PUTORATION sukwRY REF LOG gf CS ON0101M ANGLE AT TOP PhR� 10" 9 10617 Note Pcicr to Pod%xtion D13 for hestoncal pc-f data NTERVAL O4nL5- L 5h1JT 5QZ 10612 10668 O ' 02X14M 3,W8' 6 10682 10707 O 02)04j00 3-:V8' 4 10745 - 13759 O zoo1 L-96 IM' 4 10774 13820 O 02/1i198 1 a i i 668i' D 17T X 4 I12' XO 4 5'8- VW+DOIN fi958 f 498' - ----- ------ 14343' fr,c4 1 rTaktti , ; ++(le r,- tea' I —__ 1037T 14 19' W, X NIP 9) = 3-81" f 103r 4 u2' PX PLUG (02 G7 14) fF— _j4"i!2' T\iroYaC; vi-f T0399' Tat L7" O.R. 26Y, L 80 0.0363 upl, 11069' 0 - 6 2 J6- r]ATF RF'd F)Y I COLUNTS t'NITF RFV 9Y 000AWM 00IMI OFOCI'WLOOKLETON 02110114 WTIAU SET PXVLUC(02C17! -4, 02'11l98 VA?R}CO'!ER _-- 11!191f10 SL JH COiPNUUMTOCANVAS ` O-IV5101-- 6Q'11>b2 RrilD L�Rt'rLG'1Y5r� _� TTF ` 110914' M 00F PAY LRIT VOB-L 13- 06A PEFUTNo 197-2180 AR No W02420642-(11 PUC 13 MR R14L 164T FU & 80' F'4V- BP Exploration (Alaska) Inc. Douglas A. Cismoski, P.E., BPXA Wells Intervention Manager Post Office Box 196612 Anchorage, Alaska 99519-6612 June 5, 2015 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 RECEIVED • i AOGCC 0 Subject: Prudhoe Bay Well 04-09 (PTD #1760300) Request for Administrative Approval to Continue Water Injection Operations Dear Ms. Foerster, BP Exploration (Alaska) Inc. requests approval for continued water injection operations into Prudhoe Bay Well 04-09 (PTD #1760300). The well exhibits inner annulus by outer annulus communication. A pressure test of the inner annulus to 2500 psi on 08/13/2014 passed per IA pressure loss criteria. A pressure test of the outer annulus passed to 1200 psi on 8/12/2014. 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 with infrequent bleeding. Consequently, no repairs are planned at this time. In summary, BPXA believes Prudhoe Bay well 04-09 is safe to operate as stated above and requests administrative approval for continued water injection operations. If you require any additional information, please contact me at 564-4303 or Kevin Parks/ Whitney Pettus at 659-5102. Sincerely, Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments: Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks Flow Station 2 Operations Team Leader Patti Phillips Ryan Daniel Prudhoe Bay Well 04-09 Technical Justification for Administrative Approval Request June 59 2015 Well History and Status Prudhoe Bay Well 04-09 (PTD #1760300) exhibits inner annulus by outer annulus re - pressurization. A recent MIT -IA and MIT-OA passed, demonstrating competent tubing and production casing. Inner and outer annulus operating pressure is maintained below MOASP with infrequent bleeding. Recent Well Events: > 06/06/12: MIT -IA Passed to 4000 psi > 06/09/12: AP Flush returned 7 gallons of AP > 07/10/12: AOGCC witnessed MIT -IA Inconclusive (J. Jones) > 07/13/12: PPPOT-IC Passed to 3500 psi > 07/14/12: MIT -IA Inconclusive > 07/29/12: MIT-OA Passed to 2000 psi > 08/17/12: MIT -IA Passed to 2500 psi > 09/10/12: AOGCC MIT -IA to 2300 psi Inconclusive due to OA response (J. Jones) > 09/21/12: AP Flush returned 12 gallons of AP > 10/02/12: 10 Day OART OA BUR -93 psi/day with IAP at 1360 psi > 10/04/12: AP Dump returned 20 gal of AP > 06/02/14: PPPOT-T/IC Passed, MITIA Passed to 2500 psi > 08/12/14: MIT-OA Passed to 1200 psi > 08/13/14: MIT -IA Passed to 2500 psi 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. Limit well to water injection operations. 3. Submit a report monthly 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. s. ., 1o;IIS "MT Prudhoe Bay Well 04-09 Injection Plot Prudhoe Bay Well 04-09 Schematic TRFE - E _ia MC E-Ev, = 52 l', iKb KQP fl'p 75 , 7?' _9_57,5'7 -6-:] r- 236a 3 3,8'r:5G 12X 1,41 J ED U, - 1 _-; -34 2954' Minimum ID = 2.992" @ 10786' 4 112" NO-GO SETTING SLEEVE Ir nYETY NOTES: H2S READ NGS NVERACE 125 u, pmm, wHEN or4 mi. WELL A EQUIRES A SSSV -WHEAI OM ML DEPTH BFnVFFP4 HTFA OF 5-1 j2' - SEAL ASSYANQ TOP OF 507 PBR SEA- ASSY IWAS INSERT-ED AND T, BG SPACF-13 OUT PER RIG REPORT 2613' 1 .- - - ittdil8' is - , x i4 I bi,, 14 L Slack u A 151� iwr j 3C. 174 L-BC 0232 W. ID 4.892 -41 —iow 130' pa r4 A5SY ��,-,2- 7_30SEA: ASEI IMOSE-A-8 D=488' 1057 4— Ci22' 7- =ERFORA. .4 SUhWAFZY CS bN',15MM6 a Nszie Refel- �cc,"ur 22 for t&LoF!cat ;er' dais SZE SFr ^ NTEWAL --P-,-'-rz CATE, 0 L 1 fWi %A Nk 6L'O [A I NO X- L ei;t, li I SLV. IL) 2 93'c il' CAAM, WOW 0 811' l 1 jr, 1 --- i0814, _ET,7_ �71 bpi U 3 V J�vl :Ax! loel5 xm 1 j24 0 1,140 186� ngn-ias I I io A3 09?, i i 067; N 296 :, t10 :13! - Dpi 0 104' 1 12060, -d lzm, LIA ill-V llY H Al-Cl+W5 tiNU-LF- PEWCORI-EKTONS 09rWV1 CHKAK RAFO n2iUSll WAV ADCEDSSSVSAFFrYlIiQ—,r WIMPOC 3712' —S:Akal LKH, Tn-AX, ACCED F126 2A7-71-1 •V07E i?i'Ql;Ot OF, y J4 1 V%-1 134 5 SEc 2-7 % J25 ca-1 & 6-421 UP j:Apl*to1i0(, JAIA4 k*j by BP Exploration (Alaska) Inc. Ryan Ryan Daniel, Alaska Wells Integrity and RECEIVED Compliance Team Lead Post Office Box 196612 APR 0 2 2015 0 Anchorage, Alaska 99519-6612 AOGCC April 2, 2015 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well 17-08 (PTD # 1810740) 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 17-08. The well previously had a production casing leak at 5400' which was repaired with a cement squeeze per Sundry # 314-477 on 01/08/2015. A passing MIT -IA to 2,500 psi was conducted on 02/16/2015, indicating the success of the repair and that the tubing and production casing are competent. The annulus cement top was logged at 4679' on 02/28/2015. On 03/27/2015 a water flow log with temperature warmback passes over the cemented annulus interval showed no upward movement of fluid while the well was on injection. For continued operation of the well the inner annulus operating pressure shall be maintained below the MOASP of 2000 psi. In summary, BPXA believes Prudhoe Bay well 17-08 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 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. SincerE Ryan Daniel BPXA Wells Integrity and Compliance Team Lead �1 1 Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks Flow Station 2 Operations Team Leader Patti Phillips Ryan Daniel Prudhoe Bay Well 17-08 Technical Justification for Administrative Approval Request April 2, 2015 Well History and Status Prudhoe Bay injection well 17-08 (PTD # 1810740) had a production casing leak at 5400' which was repaired with a cement squeeze per Sundry # 314-477 on 1/8/2015. The post squeeze MIT -IA passed demonstrating competent tubing, production casing and cement. Recent Well Events: ➢ 01/08/2015: IA cement squeeze completed ➢ 02/16/2015: MIT -IA Passed to 2500 psi ➢ 02/28/2015: Cement top Logged at 4679' ➢ 03/27/2015: WFL and temperature warmback log indicate no upward movement of fluid in the IA across the cemented interval. ➢ 03/31/2015: AOGCC witnessed MIT -IA 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 barriers 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. Initial oxygen activation or water flow log to prove no flow across the squeeze cemented interval. 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 and MIT-T 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 17-08 TIO Plot 17-08 TIO Not ffm 2 I'M 1 GOc B 11 Tbg IA OA ODA OOOA On Date Stad/&d 01/01/2015 3/30/2015 Ffii4—�-' TIO Gd Save to CO)owd Cu. Value X 12/"14 y 1.214 Well 17-08 Injection Plot DateStait/Erid 0172015 a/30/2DI5 IN Gw tog Sal. ON 9 X�C, Co Value X 12127J2014 y 1.282 X�, 3 OOC 2XIC, 57 , a vs io el _,, 79 .11 C I I.,f � , 5 (V i S I S I f Bll�°NI $ 13 19, i 5 9J,2615 TREE = Cw VAt3LHEAD == FMC ACTUATOR= BAKFRC OKB E EV = 71' BF ELEV = K _i- _.... Max Angle = 5700' 22" @ fi900' '20' OONi)I,IC:TOR { , LBtum IAD 907Z DatumfVD= 88W55 3/8' CSG, 72%, L-80, D = 12 347" 2"1' 13 TOC (SVYS MSCdNT 1_CXi 9-5/8- CSC', 47#, L-80 BTCJ&L t XO TO S0035 9TC ALGOMA I 1 w SAFETY NOTES! H2S READINGS AVERAGE 126 ppm �(�/' WHEN ON MI— WELL REQU RES A SSSV WHEN ON MI _ 19ag' 5-12" — X —, D = 4.567- 15 12' TBG, 1 /s, L-8o, .0232 bpf, D 44.892- 84ss TBG STk B GUT (03/091101 - f 84W Minimum iD = 3.958" @ 8b81' 7" X 4-1/2" XO (TBG PARTED) Tre- TBG, 170, L-80, .0232 bpf, D = 4.892' ;—E $f4' 5-12" THG, 17#, L-80 8ROAB-MOO, a576' 4232 bpf, D = 4 892 f FISH CIBP (PLISHED DH 0228115} l t___ TOPKJF7"L1�2�-- 8606' 4..1t7' TRC R-. 12 6tl, 1490 Rtff j, f—( 7 .0152 bpf, D = 3.958- (BTM PARTED TBG} I '- 9-S18` CSG, 47M. SOO-95 BTC A,-GOMA, D = 8.681" I- sm PER ORATION SUM,WRY REF LOG: BHCS ON 0Bd26181 ANGLEAT TOPP5T.11° (p 8%5' Note Refer to ftducbon DB for hrtoncal pert data SRE SPF NTERVAL Opn/Scjz SHOT SM 3-3/8' 4 8985 - 9008O 173/2789 3-1/8' 4 W90 - 9118 O 03/14/82 3-U8' 4 9137- 9165 O 03/14/82 3-V8' 4 9178-9213 C 03/24/84 3-38" 4 9313 - 9333 C D&Q2188 3-318' 4 93M .9414 C 08722168 3.378- 4 9411, 9440': C O6l22188 7- LNR. 29@, L-80 ORD AB MOQ .0371 bpf, D = 6.184" I-1 973W 8294"-829G HTBGgRcH(122wi4) 8314' S-12" f i:S X NP, D = 4.562� 8848' H9-518" X 5 112" f F9 TNT PKR, D = 4 85' 9387 I -A 5-12" HES X NIP, D = 4 567 8470' I-j9-5/8- X 5-112- UNQLIE OVERSHOT iiw-7-i 9-5/8" X 5-12' TM/ M BP T WR, D =4.882- a532' 5-12' HES XN NF', D 4 455' $$34' 5-12' PDRT® 5U6 8567 S tl2`SEALASSY W/OSFALS w(7" STOP CXILLAR & MIAESHOE D - 4.938' — - 85T8' 9-518" X 5 112` BOT & H RCR D 4 7:i -1I581 7' X d-72' XO, D - 3.958' (TBG PARTED} 660b' 7"X 4-12' LNR HGRw/D�ACK SLV, D=?7 1 4 112' PARTED TBG TAIL CALMR O5/02114 (w JCAMCO OB-6 NIP & VVLEG, D - 3.813') 9170- -�TOPOF FL: (TAGGED 11J20110) S2'711• � �c%n &^.AA.fVD t"LUC tecr 12JC"Jlael�] 9710' DATE REV BY 1 CO WANTS 1 DATE REV BY COKOAWS 07/04/B7 RWN 3b' OFWMN lL COMPLETION 101/13/15 JCFf.AuD OTT RETAI*RCMT (01107115) 0=4197 N ES FIWO v 01/15115 PJC MN D C OR14 CTMH iO4/14/10 MEM RWO _..._.._.........-- —J02rM1-5 C-& P L LL CAR' C MT RETAMP 11/14 114 ML1tPJC (PART® TBG (0502114 CALIPER3102115 CJS/ PJC ADD LOG FOR TOO FKR D URIATE 12/15/14 JTUJK FULL NIP PJ' PATCH (17J14114) 01IM15 GTWA44 SET ClPffBGR4Q1(1212TM14) BKR PKR 3.BAENT PRUOFpC BAY UdT VAIL. 17-08 PERWT N1 '1810740 API No. 50-029-20602-M SEC 22, TlOR R15E 2359' FNL & 955' FWL BP EXPbration (Alaska) BP Exploration (Alaska) Inc. RECEIVED bp Douglas A. Cismoski, Wells Intervention Manager MAR 0 2 2015 Post Office Box 196612 Anchorage, Alaska 99519-6612 C AOGC February 25, 2015 Ms. Cathy P. Foerster Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Prudhoe Bay Well PSI-09 (PTD # 2021240) 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 Bav well PSI-09. The well began experiencing IA repressurization in December 2014. A passing MIT -IA to 2,500 psi was conducted on 12/08/2014, indicating that the well has competent production casing, packer and tubing. The recorded IA build up rate while the well was on injection between 1/26/2015 and 2/4/2015 was -158 psi/day. Maximum wellhead injection pressure during this period was 1850 psi. A subsequent MIT-T was conducted to 2500 psi on 2/19/2015 to verify the tubing integrity. In summary, BPXA believes Prudhoe Bay well PSI-09 is safe to operate and requests administrative approval for continued water injection operations, managing the IA repressurization with periodic annular bleeds. If you have any questions, please call me at 564-4303 or Whitney Pettus/ Kevin Parks at 659-5102. Sincerely, Douglas A. Cismoski, P.E. BPXA Wells Intervention Manager Attachments Technical Justification TIO Plot Injection Plot Wellbore Schematic Cc: Doug Cismoski Pettus/ Parks Flow Station 2 Operations Team Leader Patti Phillips Ryan Daniel Prudhoe Bay Well PSI-09 Technical Justification for Administrative Approval Request February 25, 2015 Well History and Status The well began experiencing IA repressurization in December 2014. A passing MIT -IA to 2,500 psi was conducted on 12/08/2014, indicating that the well has competent production casing, packer and tubing. The recorded IA build up rate while the well was on injection between 1/26/2015 and 2/4/2015 was -158 psi/day. Maximum wellhead injection pressure during this period was 1850 psi. A subsequent MIT-T was conducted to 2500 psi on 2/19/2015 to verify the tubing integrity. The well is currently shut in and secured with a downhole plug. Recent Well Events: ➢ 12/9/2015: MIT -IA Passed to 2500 psi ➢ 1/26/2015-2/4/2015 BUR= -158 psi/day ➢ 2/19/2015: MIT-T Passed to 2500 psi Barrier and Hazard Evaluation The primary and secondary barriers systems consist of the tubing, production casing, packer and associated hardware. A pressure test of the inner annulus and tubing passed to 2500 psi, demonstrating competent primary and secondary barriers 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. Record wellhead pressures and injection rate daily. 2. Submit a monthly report of well pressures and injection rates to the AOGCC. 3. Perform a 2-year MIT -IA to maximum injection pressure. 4. The well will be shut-in and the AOGCC notified if there is any change in the well's mechanical condition. Well PSI-09 TIO Plot D- 5-,./Etl PSI n TIO PkA 2125m14 TIO Gad 07/07/2014 y 3.109 Tbp IA CIA OOA ♦ OA 0 Well PSI-09 Injection Plot 1— sx—E'd 2125,12011 212512016 PU- C— Ad- x 021121MIS y 2081, TREE= 7-VIP; 5KC1W WELLHEAD = 13-513' 5K iMC ACTUA Tip R = KS. ELEV = 50.55' e K Al 0 0 PSI-09 I SAFETY NOTES: WELL REWIRES A SSS V. DATE REV BY CONARITS OATE ReJ BY cmq&ws 07F22r92 D4OT0{ ORIGMLCO6PLE IDN P17+30= -MINTGC IP6iFS A a" TT LOGGED 9"USOM SVO'1P ChrARGEKSE 11F19.(92 CAS AOPERFS 07l11f11 Lj3j.-D ADDED 55SVSAFETY NUTE FRUDHOE SAY LUT WELL: PSW9 IERACIT W: p2a? 1243 AR W: 53-CH-23595 SGC 15, T11 K R15E, 3E76 ML & 4351WEL SP Exploration (Alaska) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to Winton_Aubert@adman state.ak us, Bob_Fleckenstein@admen state.ak us; Jim_Regg@admin.state ak.us; Tom_Maunder@adman state ak.us OPERATOR: FIELD / UNIT I PAD: DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. Prudhoe / GPB / PSI-09 02/19/15 Laurie Chmer Packer Depth Pretest Initial 15 Min 30 Min Well PSI-09 Type In) W TVD 8,034' Tubingl 20 2,5111 2,4491 2,4251 Interval O P.T D 12021240 Type test P Test psi 2009 Casin gi 20 5901 5811 576 P/F P Notes: Internal diagnostic test OA 0 0 10 10 MIT-T post TTP set WeIll Type In) I TVD I Tubingi I Interval P T D Type test Test psi I Casing P/F Notes: I OA Welli Type In) I TVD I Tubingl Interval P T.D Type test Test psi I Casing P/F N otes: I OA Well Type In). TVD Tubingi I Interval P T D.1 I Type testl I Test psi I I Casingl IP/F Notes: I OA Welli I Type In). TVD I Tubingl I I I Interval P T.D. Type test Test psi I Casing P/F Notes: I 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 T = Test during Workover O = Other (describe in notes) MIT Report Form BFL 9/1/05 MIT PBU PSI-09 02-19-15 MIT-T (2) As STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Email to Winton_Aubert@admin.state ak.us; Bob_Fleckenstein@admin.state ak us, Jim_Regg@admin.state ak us; Tom_Maunder@adman state ak.us OPERATOR: FIELD / UNIT / PAD DATE: OPERATOR REP: AOGCC REP: BP Exploration (Alaska), Inc. Prudhoe / GPB / PSI-09 12/08/14 Jack Disbrow Packer Depth Pretest Initial 15 Min 30 Min Well PSI-09 I Type Int I W TVD 8,034' Tubing 1,264 1,264 1,264 1,264 Interval O P.T D 2021240 Type test P Test psi 2009 Casing 1,1451 2,5051 2,4971 2,490 P/F I P Notes: MIT -IA to evaluate IA repress unzation OA 2 150 162 169 Welli Type Inj I I TVD I I Tubingi I I I Interval P T D Type test I Test psi I I Casing P/F Notes: I OA Welli Type Int I I TVD I Tubingl Interval P T D Type test I I Test psi I I Casing P/F Notes: I OA Weld Type Inj I I TVD I I Tubing Interval P T D Type test I Test psi I I Casin P/F Notes: I OA Well Type In/. I TVD I I Tubingi I Interval P T.D I Type testl I Test psi I I Casing P/F Notes: I 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 T = Test during Workover O = Other (describe in notes) MIT Report Form BFL 9/1/05 MIT PBU PSI-09 12-08-14 (2).xls by October 31, 2014 RECEIVED NOV 0 3 2014 AOGCC Commissioner Cathy Foerster, Chair Alaska Oil & Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, Alaska 99501 Reference: Grind & Inject Project Annual Performance Report Dear Commissioner Foerster: 4114400holow �•: Zvi Xt- :�� 1010 0 ,e BP Exploration (Alaska) Inc. 900 East Benson Boulevard P.O. Box 196612 Anchorage, Alaska 99519-6612 (907) 561-51 1 1 Enclosed is the Annual Performance Report for waste slurry injection for the Grind and Inject project located near Drill Site 4 in the Prudhoe Bay Unit. This report is submitted to satisfy the requirements of Area Injection Order #41F corrected, Rule 10. This requirement is very similar to an EPA report requirement regarding Prudhoe Bay Unit UIC Class I injection wells contained in EPA permit AK-11008-A. The report covers the period from October 1, 2013 through September 30, 2014 and was structured to satisfy both the AOGCC and the EPA requirements. Should you have questions concerning the contents of this report, contact me at 564-4692. Sincerely, Michael L. Bill Senior Staff Engineer ,* " Cc: A. Cooke MB 3-3 M. McAnulty MB 4-4 R. Daniel MB 7-1 G. Crawford MB 11 Harrington/Collver PRB 42 Srock/Gross PRB 42 Reyes/Kany PRB 42 Disbrow/Climer PRB 20 M. Nelson, ConocoPhillips J. Lederhos, ExxonMobil Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class I Permit AK-11008-A AOGCC Area Injection Order #4F, Rule 10 Annual Performance Report October 1, 2013 through September 30, 2014 This Annual Performance Report documents waste slurry injection on the Surfcote Pad near Drill Site 4 in the Prudhoe Bay Unit for the period October 1, 2013 through September 30, 2014. This report is submitted to satisfy the requirements of both EPA UIC Class I permit AK-11008-A, Part II 3 c 7 and AOGCC Area Injection Order (AIO) #4F corrected, Rule 10. Additional information requested in a letter from the AOGCC (Regg to Bill 12/22/03) is also included. The report contains a brief description of the current project status, a summary of the disposal well performance data acquired during this period and operational plans for the next year. Project Status The Grind & Inject (G&I) Project at the Surfcote pad was undertaken in 1998 by the owners of the Prudhoe Bay Unit, Initial and Lisburne Participating Areas, and the Kuparuk River Unit to dispose of drilling muds and cuttings stored in reserve pits. Other non -hazardous wastes processed through the G&I Plant included those referenced in AIO #4F, Rule 2 as Class II wastes, consisting of RCRA-exempt drill cuttings and oily solids from pipeline pigging, vessel cleanouts and well workovers, and RCRA-exempt liquid wastes such as used drilling mud from on -going North Slope drilling operations. EPA issued Class I UIC permit AK-11008-A for the Grind & Inject Project effective September 1, 2007. Authorizations to inject Class I substances were received on January 18, 2008 for wells GNI-02A and GNI-03 and on May 6, 2008 for GNI-04. Well GNI-01 remains a Class II only disposal well. All non -hazardous wastes injected for disposal in the GNI wells during the report period are within the description of wastes referenced in EPA UIC Class I Permit AK-11008-A, Part II C 3 7, the UIC Class I permit application submitted in November 2006, or in Area Injection Order 413, Finding 7 as incorporated in AIO W. . Several lined pits comprising the "material transfer station" (MTS) at DS 4 were operated to temporarily store ongoing drilling solids, oily solids and other wastes when necessary. On an infrequent basis, other wastes were injected directly into G&I wells using temporary equipment staged on the Surfcote pad. As of September 30, 2014, project injection has included 63.2 MM barrels of water, 93.6 MM barrels of slurry containing 5.5 MM tons (6.1 MM cubic yards) of excavated reserve pit material and other waste solids, and 8.5 MM barrels of fluid from ongoing drilling operations. Exhibit 1 summarizes this data. Operations Operations during the year were affected by seawater supply interruptions due to high winds, power outages and maintenance work at Flow Station 2, Drill Site 4 and the Seawater Treatment Plant. G&I maintenance activities included an extensive inspection program of the piping and processing equipment within the plant and the pipelines to the wells. Major operations and maintenance activities included replacement or repairs of process valves and piping, and well manifold and valves. Solids processing in the G&I plant was shut down during the 2013 summer until late January 2014, and from late March through the present. Disposal of ongoing liquid drilling wastes and water from pit dewatering operations continued during much of the summer shut down period. Solid wastes accumulated during the shutdown periods were stored at the MTS and processed when the full plant was in operation. The pace of excavation from the production reserve pits was reduced in 2010 with the concurrence of the Alaska Department of Environmental Conservation. Batch processing of solids rather than continuous processing has been used as needed since. Options for the disposal of material remaining in production reserve pits are being evaluated. Direct injection was utilized to dispose of oily waste accumulated in the MTS and during shutdowns of the Prudhoe Bay Unit Pad 3 oily waste disposal facility associated with wellwork and equipment maintenance. Well Operations and Monitoring The four GNI disposal wells are located on the Surfcote pad and continue to be available for disposal. Well GNI-01 has been shut-in due to tubing damage since May 2007, but it could be used for limited Class II direct injection pending current mechanical integrity testing, or for observation purposes if needed. It was replaced for Class I waste and slurry injection by well GNI-04 which began in May 2008. Well GNI-02A was sidetracked to a new bottom hole location in November/December 2006 and is an active Class I waste and slurry injector. Existing Class I well GNI-03 has remained active since a workover in December 2009 to replace damaged tubing. Each well is perforated in the Ugnu formation between 6400 and 6600 ft. TVD. GNI plant discharge rate, temperature and slurry density, along with well injection pressure and temperature and annulus pressures are continuously monitored in the G&I Plant control room. Injection takes place into one well at a time on a rotating schedule. After each injection cycle, the newly shut in well is flushed with water and freeze protected with new product methanol mixed with water. Exhibit 4 lists the injection cycles and the well work and surveillance activities during the report period. The injection history and performance for each well is shown in Exhibits 1, 2, 3, 5, 6 and 10. Peak slurry injection rates are normally between 25,000 and 35,000 barrels per day with between 2,000 and 3,500 cubic yards per day when solids are processed. Injected slurry density averaged about 9.5 ppg when solids were being processed (Exhibit 6). Surface injection pressure is heavily influenced by the slurry injection rate, slurry density and to some extent slurry temperature due to viscosity dependence on temperature and the impact of injection temperature on formation stress. Daily average surface injection and calculated bottom -hole injection pressures (BHIP) are shown in Exhibit 6 for each well. BHIP is calculated to account for the effects of the hydrostatic head and fluid friction of the slurry column. The calculated bottom hole injection pressures in each well have normally shown relatively stable injection pressures over the last year. However some cycles have shown a period of reduced injection pressures early in the cycle. All three active wells have maintained good formation injectivity with no sign of formation plugging. By design, the outer annulus (OA) of each GNI well is in weak pressure communication with the formation adjacent to its surface casing shoe set at about 4000 ft. TVD (GNI-03 and GNI-04) and about 2800' TVD in the GNI-02A sidetrack. The surface pressure in each outer annulus is monitored as potential indicator of any significant fluid movement above the approved injection interval. The OA pressure is also quite sensitive to thermal expansion or contraction of the annulus fluids resulting from the injection cycle and injection fluid temperature variations. The inner and outer annuli of each well are closely monitored during a well swap and periods of higher temperature injection, and the annulus pressures are bled as necessary. Due to the communication with the formation, OA pressure changes related to thermal effects begin to dissipate within a short time. There have been no significant sustained pressure increases adjacent to the surface casing shoe and no abnormal or unexplained annulus pressures observed during the report period. Each GNI well is equipped with control line tubing open ended within the inner annulus (IA) to about 1000 ft. This line allows several hundred feet of nitrogen cushion to be maintained in the inner annulus (IA) to dampen the pressure changes due to thermal expansion or contraction of the annulus fluid. There has been no indication of tubing or packer leakage observed in any of the GNI wells, although the IA pressure may need to be bled during periods of high temperature injection and re -charged during periods of cooler injection. Exhibit 10 contains daily average tubing, IA and OA pressures for each of the wells. Dates when the annulus pressure was bled or re -pressured are also indicated. EPA witnessed mechanical integrity tests of the inner annulus are required annually under the Class I permit. The AOGCC requires an MIT -IA every two years in slurry injection wells under AIO 4F, Rule 6. Successful MIT -IA tests were performed in GNI wells 02A, 03 and 04 on September 20, 2014. EPA representatives witnessed each of these MIT -IA tests. Memory caliper logs were run in GNI wells 02A, 03 and 04 to inspect the 7" tubing strings in 2014. GNI-01 has remained shut-in since May 2007 due to the level of tubing damage. The following table lists the observed maximum metal loss in the tubing and the casing below the packer from the caliper logs run during the report period. Well Date Max Pit Penetration Max Cross -Sectional Wall Loss Tubing Casinq Tubinq Casing GNI-02A 07/21/14 36% 34% 25% 18% GNI-03 07/30/14 24% 59% 11 % 27% GNI-04 07/06/14 34% 31 % 18% 15% Well Surveillance and Testing The cycling of wells on injection generally allows well surveillance and maintenance activities to be scheduled with little disruption to G&I plant operations. To minimize freeze protection concerns, repeat well tests and logs are usually scheduled in the summer. The shut-in temperature/pressure survey results for 2014 and prior years are shown in Exhibit 7. Repeat shut-in temperature/pressure logs were run in the wells in July. Based on the fill tags and the temperature profiles, all injection continues to exit each wellbore through the perforated intervals. The temperature logs have similar character to the previous logs in each well. Consistent with the 2013 results, the temperature logs have shown less than 500 feet TVD of vertical fluid movement. Since the GNI well bores are deviated and the effective depth of investigation of temperature logs is limited, the full extent of injection through vertical fractures may not be detected by the temperature logs. Static reservoir pressures obtained with the GNI-02A, 03 and 04 shut-in temperature/ pressure logs were slightly higher than the 2013 measurements. The pressures were measured 7 to 12 days after the wells were shut in and were converted to a depth at the top of the perforations for each well: GNI-02A 07/21/14 3092 psi (+45 psi from 2013), GNI-03 07/30/14 3089 psi (+25 psi from 2013), GNI-04 07/06/14 3063 psi (+23 psi from 2013). Repeat step rate tests (SRTs) were performed in wells GNI-02A, 03 and 04 in July and August. The repeat SRT procedure normally includes a step up portion at the beginning of a well cycle followed by a step down portion. Due to a previous cycles with a period of low pressure injection, the procedure was changed for GNI-02A and GNI-04 this year to perform the step down test before step up portion. Each SRT was analyzed using two methods to provide additional insight, a conventional analysis and a superposition method. The step rate test in wells GNI-02A and GNI-04 exhibited an unusual character with no indication of matrix flow. This has been interpreted as injection into a pre- existing fracture or fracture network possibly held open by injected solids. During the test, there was a second fracture was re -opened. GNI-03 initially showed a possible mixture of matrix and conductive fracture flow and later re -opening another fracture. No fracture closure was seen during the step down portions of the tests. Exhibit 8 discusses the 2014 step rate test data and analysis results. As in the past, SRT's confirm fractures are the primary disposal mechanism. Repeat surface pressure falloff (SPFO) tests were run in wells GNI-02A, 03 and 04 in July and August. Surface pressure falloff tests were run in the summer to avoid rate fluctuations due to freeze protection immediately prior to shut in. Also, since a well cannot be shut in while injecting slurry, each repeat SPFO test is run after a period of seawater water injection containing only mud liquids. No drilling mud was injected in the 24 hours prior to shutting in the well and the injection rate was stabilized. The SPFO tests should be viewed as representing a snapshot in time that may not completely reflect the downhole flow conditions present during the entire year partially due to the differences with fluid rheology under actual slurry injection. As with past tests, calibrated surface memory gauges were used to record the pressure falloff data. 4 Exhibit 9 discusses the 2014 SPFO test analysis results. Several reservoir flow models were used in an attempt to obtain a type curve match of the data. The SPFO data from each of the wells was best matched using a radial composite double -porosity (RCDP) reservoir model, indicating the presence of an inner damaged zone some distance from the wellbore. Fracture flow within the inner damaged zone was also evident in each of the SPFOs. In GNI-02A and GNI-04, there was indication of injection into more than one main fracture and possibly a network of secondary fractures initiated around the main fractures. Storage Mechanism and Disposal Domain As reported in the past, a number of industry studies have been conducted to understand the downhole storage mechanism in slurry injection operations. These include two major industry studies: the Drilling Engineering Associates (DEA) 81 Joint Industry Project (JIP) laboratory study and the Mounds Drill Cuttings Injection JIP field pilot study. Individual operators have also reported monitoring and well testing programs to delineate the storage mechanism and geometry. Many of these studies and monitoring programs agree that multiple fractures are created during periodic injection operations. Step rate tests and pressure falloff tests of the GNI wells have also showed signatures of multiple opening or multiple closure events in the past, indicating multiple fractures from GNI operations. The result is likely a complex disposal domain consisting of a series of fractures developed over time with different orientations. Branching fractures may also be a part of the storage mechanism. This disposal domain allows for the storage of large amounts of solids. Grind and Inject fracture modeling was updated in 2006 using a modified conventional hard rock fracture simulator adjusted for soft rock behavior and assuming the disposal domain described above. The layer description was extended upward and downward to include 22 layers. The updated model runs predicted fractures to be contained below 5900 ft. TVD at that time, about 600 ft. above the perforations in the original GNI completions. At some point the increasing stress due to solids storage in the fractures of the disposal domain will create conditions resulting in possible additional upward fracture extension. The model results indicate fracture growth to near 5000 ft. TVD at some time beyond the year 2020, still well below the top of the approved interval at about 4500 ft. TVD. While the primary G&I surveillance techniques (temperature logs, step rate tests and pressure falloff tests), the results from a prototype bore hole gravity meter reported in 2010 and the model results provide differing inferences as to the size of the fracture system (partially due to the specific conditions of each test), all indicate limited upward movement of the injected material and confinement well within the approved interval specified in EPA UIC Class I permit AK-11008-A, Part II 3 c 4 and AIO #4F, Rule 2. Well Plans Well GNI-01 has significant tubing damage and has injected over 1.6 MM cubic yards of waste drilling solids. Well GNI-01 could be available for occasional direct injection of Class II materials pending current mechanical integrity testing, and to observe various facets of the slurry injection process if needed. Routine waste injection is expected to continue to be cycled between the three active Class I disposal wells. Operational Plans The operational plan for the next twelve months will involve similar activities to those in recent years. Discussions are ongoing with Alaska Department of Environmental Conservation concerning the scope of the remaining production reserve pit closeout activities required by the State of Alaska's Inactive Reserve pit Closure regulations. While one feed for the G&I plant will be excavated drilling mud and cuttings from exploration reserve pits and well sites, the pace of excavation from the production reserve pits will likely remain reduced. As was the case in 2013, solid waste material will be processed in batches rather than continuously, except when the mill is shut down for maintenance, during well switches and for brief periods due to weather or utility outages. Class 11 liquids and solids from on -going drilling operations will be processed at the G&I plant on a periodic basis determined by the drilling and well workover activities. Oily solids will be accepted at the material transfer station and processed at the G&I plant during winter months when the material can be handled in a frozen state and mixed with other solid wastes. Non -hazardous Class I materials will be processed and also injected in the three active GNI slurry injection wells. Direct injection of other non -hazardous or exempt wastes will be utilized when necessary. Melted snow accumulating in reserve pits will be injected by the GNI plant in the summer as needed. Each of the three active GNI wells will be used for injection on a rotating schedule as described above. Prudhoe Bay Unit, Grind & Inject Project, Surfcote Pad Injection EPA UIC Class 1 Permit AK-11008-A AOGCC Area Injection Order #4F, Rule 10 Annual Performance Report October 1, 2013 through September 30, 2014 List of Exhibits 1. GNI Surfcote Injection Summary 2. GNI Injection Bar Graph 3. a,b GNI Solids Injection Bar Graphs 4. GNI Surfcote Well Surveillance Activities 5. b,c,d GNI Wells Injection Bar Graphs 6. b,c,d GNI Wells Daily Average Data Plots 7. b,c,d GNI Wells Temperature Logs 8. GNI Wells Step Rate Tests 9. GNI Wells Pressure Falloff Tests 10. b,c,d GNI Wells TIO Pressure plots 7 Exhibit 1 G&I Injection Summary Cumulative Thru September 30, 2014 Total GNIA GNI-2 GNI-02A GNI-3 GNI-4 Shut -In F&A Active Active Active Water Injection (MM Barrels) * 63.2 10.2 8.3 13.9 19.9 10.9 Slurry Injection (MM Barrels) ** 93.6 22.6 18.4 12.5 32.0 8.1 Total Injection (MM Barrels) *** 156.8 32.8 26.8 26.4 51.9 19.0 Solids Injected (MM Tons) 5.5 1.5 1.2 0.6 1.9 0.3 Solids Injected (MM Cubic Yards) 6.1 1.6 1.3 0.6 2.2 0.4 Drilling Fluid Injected (MM Barrels) 8.5 1.3 1.0 1.8 2.9 1.4 Direct Injection (M Barrels) **** 366 38 28 57 162 82 * includes bypass sea water and produced water injected during plant outages and upsets "* includes all fluids pumped from the G&I plant *** includes slurry, water and direct injection **** Includes oil based mud, contaminated crude, other waste and flush water pumped at the well site 0 1/1/2013 3/3/2013 5/3/2013 7/3/2013 9/2/2013 11 /2/2013 1/2/2014 3/4/2014 5/4/2014 7/4/2014 9/3/2014 11 /3/2014 Daily Injection barrels N N W CO 4. 4 C" 0 O 0 O O C7 0 0 0 0 m x a rt N Z v CD� n O� O_ 3 CD Cr CD 4,500 4,000 3,500 0 T 10 y 3,000 0 2,500 c 2,000 Z, 1,500 1,000 0 M \ O O Exhibit 3a: GNI Daily Injected Solids by Well GNI-2A GNI-3 GNI-4 Cum Yards Injected M M M M CO P P P P P r P r P P P \ \ \ \ \ \ \ \ \ \ \ M M M N N N O O O O O O O O O O O \ \ \ \ \ \ \ \ \ \ \ CO LO I� O P O O O O r O O O O 0 e- 10,000,000 9,000,000 8,000,000 7,000,000 .a 6,000,000 as c 5,000,000 M 4,000,000 E U 3,000,000 2,000,000 1,000,000 0 12 .d+ m �C .0 LL c G .co G Z CO) :E x W 5L/LO/LO VMO/L L K40/60 b L/ L O/LO b L/ LO/50 b L/ LO/£0 bL/LO/LO £L/LO/LL E L/LO/60 E L/ LO/LO E L/ L0/SO EL/LO/LO O o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O CD O O O CD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 O Lo O Ln O Ln O U-) O Ln O Ln O Ln O un O LO O Ln O O) G oD 00 f- ti CO (O Ld L V ch cM N (Nia- slaajeq pine Buillija Area Exhibit 4 Grind & Inject Well Work Summary GNI-2 I GNI-02A GNI-3 GNI-4 Event Date Comments Date Comments Date Comments 811712012 Inject Water 08117 - 09/02/12 9/4/2013 Inject Water 09104 - 09117/13 Direct Injection 9/5/2013 Direct Inject 09/05 - 09/16/13 Direct Injection MIT -IA, Place N2 Cap 9/22-23/13 MIT -IA to 1800 psi, Passed, IA N2 cap to 120' Direct Injection 10/16/2013 Inject Water 10/16 - 10/30/13 Direct Injection 1112712013 Inject Water 11/27-12/10113 Direct Injection 1112712013 Direct Inject 11127 - 12/10/13 Direct Injection Direct Injection 1/7/2014 Inject Water 01/07 - 01/22/14 Direct Injection 1/7/2014 Direct Inject 01107 - 01/21/14 Direct Injection 2/13/2014 Inject Slurry 02/13 - 03/03/13 4/312014 Inject Water 04/03 - 04/15/14 Direct Injection Direct Injection 5/18/2014 Inject Water 05118 - 06131/14 Direct Injection 5/18/2014 Direct Inject 05/18 - 05/30/14 Direct Injection 6128/2014 Inject Water 06128 - 07/12/14 Step Rate Test 7/6/2014 Step Rate Test Temperature /Pressure Log Caliper tbg-csg Surface Pressure Falloff Test 7/12/2014 Surface Pressure Falloff Test, 07/12-07/18 Step Rate Test Surface Pressure Falloff Test Temperature /Pressure Log 7/21/2014 Memory Surf-8115' CSLM: BHT=85F,BHP=3083psi Caliper tbg-csg 7/21 /2014 Caliper tbg & csg Step Rate Test Surface Pressure Falloff Test 8/9/2014 Inject Water 08/09-08128114 Direct Injection MIT -IA, Place N2 Cap 9/20/2014 MIT -IA to 1800 psi, Passed, N2 cap 1011/2014 Inject Water 10/01 - 10/xx/14 Direct Injection 10/1/2014 Direct Inject 10/01 - 10/02114 9/1712013 Inject Water 09117-10/02113 9117/2013 Direct Inject 09/17-10101/13 9/23/2013 MIT -IA to 1800 psi, Passed, IA N2 cap to 132' 10/3012013 Inject Water 10130-11/13113 12/1012013 Inject Water 12110-12126113 12/1012013 Direct Inject 12/10-12124113 1122/2014 Inject Water 01122 - 01/26/14 1/25/2014 Inject Slurry 01/25 - 02/03/14 1/22/2014 Direct Inject 01/22 - 01/30/14 3/3/2014 Inject Slurry 03/03 - 03/05/13 3/5/2014 Inject Water 03/05 - 03118/14 4/15/2014 Inject Water 04115 - 05/03/14 4/1612014 Direct Inject 04116 - 05/02/14 5/3112014 Inject Water 05/31 - 06/14/14 6/31/2014 Direct Inject05131/14 711212014 Inject Water 07/12 - 07/19/14 7/12/2014 Step Rate Test 7/19/2014 Surface Pressure Falloff Test,07/19-07/25 7/30/2014 Memory Surf-7306' CSLM: BHT=77F,BHP=3085psi 7/30/2014 Caliper tbg & csg 8/28/2014 Inject Water 08128 - 09/11/14 9/20/2014 MIT -IA to 1800 psi, Passed, N2 cap 9/22/2013 MIT -IA to 1800 psi, Passed, IA N2 cap to 102' 10/2/2013 Inject Water 10/02 - 10/16/13 10/212013 Direct Inject 10/02-10/07/13 11113/2013 Inject Water 11/13-11127113 11/16/2013 Direct Inject 11116 - 11/27113 12/26/2013 Inject Water 12/25/13 - 01/07/14 12/26/2013 Direct Inject 12/25/13 - 01/06/14 2/3/2014 Inject Slurry 02103 - 02/13113 3/1812014 Inject Water 03/18 - 04/03/14 5/3/2014 Inject Water 05103 - 06/18/14 5/3/2014 Direct Inject 05/03 - 05117/14 6/14/2014 Inject Water 06/14 - 06/28/14 7/6/2014 Memory Surf-7166' CSLM: BHT=80F,BHP=3060psi 7/6/2014 Caliper tbg & csg 7/19/2014 Inject Water 07/19 - 08/09114 8/2/2014 Step Rate Test 8/9/2014 Surface Pressure Falloff Test, 08/09-08/15 9/11/2014 Inject Water 09111 - 10/01/14 9/1912014 Direct Inject 09/19 - 09/30/14 9/20/2014 MIT -IA to 1800 psi, Passed, N2 cap Injection BIRD N N w W .P A U1 Ui O Un O C" O CT O CT O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O O 1/1/2013 3/3/2013 5/3/2013 7/3/2013 9/2/2013 11/2/2013 1/2/2014 3/4/2014 5/4/2014 7/4/2014 9/3/2014 11 /3/2014 i a 0 c 3 CC A 0 CL O O � N Pi CA) CA) A A CT O O O O O O O O O O Solids Cu Yds/Day Aea/Sp,k no Sp!IoS 0 0 0 0 0 0 0 0 0 o W o oO o oLO o LO 0 0 0 V) IT v M cM CV N � V) 0 i � II agot V W Z/£/ 6 6 KOZ/£/6 V LOZ/V/Z V 60Z/V/£ V � 0Z/Z4 £ 6OZ/Z/ 6 6 £ 6OZ/Z/6 £ LOZ/£/L £ 60Z/£/5 £ � OZ/£/£ MZ/M 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 o ui o LO o LO C ui o �n LO V q}' Cl) M CV N a- dd8 u01100ful 1 3/3/2013 5/3/2013 7/3/2013 9/2/2013 11 /2/2013 1 /2/2014 3/4/2014 5/4/2014 7/4/2014 9/3/2014 11 /3/2014 Injection BPD s N N W W A A C71 U7 O Un O Ul O Cn O Cn O O O O O O O O O O O O O O O O O O O O O O CL .A 41. Cli O O O O O O O O O O O O O O O O O O O O Solids Cu Yds/Day m x c� vt CL Q Z v 5 O� O CV Cr 11 w Q- d U ~ Q LL 0 o m H o = 2 0 m Q Q Q ^ N N N N N Z N LL IL (D ik I I + + O O 00 tl- CD 6dd o�,suoa `d dwal `wdq ejea j;W M M N O O O O O O O O O O r O 00 1- CD to � t) N - O V 6/£0/ 6 6 V 6/£0/60 V 070/LO V 6/VO/90 V 6/VO/£0 V UZO/ 60 £ UZO/ � � £ UZO/60 £ 6/£0/LO £ l/£0/90 £ 6/£0/£0 £b/60/60 Zl./60/6L Z 6/ 60/60 Z I./ZO/LO Z UZO/90 Z 6/ZO/£0 ZM040 0 0 o 0 0 0 o 0 0 0 t� Nt V C+) M N N O Isd dIHS Olen `dIHM O 01/01/12 03/02/12 05/02/12 07/02/12 09/01 /12 11/01/12 01/01/13 03/03/13 05/03/13 07/03/13 09/02/13 11 /02/13 01 /02/14 03/04/14 05/04/14 07/04/14 09/03/14 11 /03/14 WHIP, Calc BHIP psi N N W W A A C" CD O O O O O O O ; O O O N W A (n M —1 M O — — — — O O O O O O Mtr Rate bpm, Temp F, Dens*10 ppg t + + 0 t G) Z -n -n �SSt m w = (0 CO 3 V _ o -n 3 a o o o a 3 CD o a O 01 /01 /12 03/02/12 05/02/12 07/02/12 09/01 /12 11/01/12 01/01/13 03/03/13 05/03/13 07/03/13 09/02/13 11 /02/13 01/02/14 03/04/14 05/04/14 07/04/14 09/03/14 11 /03/14 WHIP, Calc BHIP psi N N w w -Al CN. Cn 0 O CT O Cn O Cn O Cr Cl O O O O O O O O O O O O O Oi O O O O O O O N W A Cn M -I M CO — — — — O O O O O O O O O O N w A U7 I O O O O O O I Mtr Rate bpm, Temp F, Dens'10 ppg t + + cu 0 v o � a o 3 0 -i C a 130 120 110 U. 100 d a. 7 r g0 m H 80 70 60 Exhibit 7b: GNI-02A Shut In Temperature Logs a Jewelry/Perfs -- o-- 2 02-28-98 BL 2Al2-24-06 BL -�— 2A 05-24-08 15da SI -+-2A 07-01-09 8 da SI 2A 06-30-10 12da SI 2A 10-22-11 8 da SI —� 2A 07-07-12 13da SI —� 2A 07-08-13 7 da SI �- 2A 07-21-14 9 da SI re Fr 4000 4500 5000 5500 True Vertical Depth ft M 6500 7000 130 120 110 100 U. 7 L 90 d a E m f 70 M 50 4000 Exhibit 7c: GNI-03 Shut In Temperature Logs ■ Perfs/Jewelry 6/6/98 Baseline 06/06/07 12day SI - -• 06/20/08 May SI, Calib Shift --f - 06/15/09 7 day SI 07/11/10 9 day SI • - 06/29/11 12 da SI 06/13/12 12 da SI —�- 06/22/13 12 da SI -■ - 07/30/14 11 da SI 4500 5000 5500 True Vertical Depth feet M 6500 7000 130 120 110 U.100 d 7 r d E 90 m M 70 -5 Exhibit 7d: GNI-04 Shut In Temperature Logs ■ Perfs/Jewelry #4 1/22/08 BL t #4 4/23/08 BL #4 1 /27/09 11 daS[ —+ #4 6/12/10 9 daS1 ■ #4 7/09/11 11daS1 ' #4 6/21/12 9 daS1 —+—#4 6/28/13 8 daS1 --+— #4 7/06/14 8 daS1 v 4000 4500 5000 5500 6000 6500 7000 True Vertical Depth feet 4%dvantek Exhibit 8 — 2014 Step Rate Tests INTER 1-al., Exhibit 8 2014 Step Rate Tests BP GNI October 2014 Step Rate Tests (SRTs) were performed for GNI wells 2A, 3 and 4 in the summer of 2014. Each SRT test procedure included two segments: a rate step-up test, and a rate step-down test. The SRT data was analyzed by Advantek International using the conventional SRT analysis method and the multi -rate superposition principle. Analysis Methods: Conventional Analysis: The conventional step rate test analysis method uses plots of the stabilized bottom -hole injection pressure (BHIP) versus injection rate for each rate during the step-up leg. For hard rocks with no existing fractures, this plot should show two distinct slopes — the early slope indicates matrix injection without fracture propagation, and the later (lower) slope indicates injection with fracture growth. The intercept of these two slopes is an indication of the fracture propagation/fracture opening pressure. Similarly, in the step- down leg of the test, the intercept of two slopes is an indication of the fracture closure pressure/minimum horizontal stress. However, in wells with pre-existing fractures, such as the GNI wells, these fractures become hydraulically conductive before they mechanically open. Typically, this effect shows up as a curvature in the plot between the two straight lines. The fracture becomes hydraulically conductive but not mechanically open when the curvature starts and is considered to be mechanically open at the beginning of the second line. However, when this typical behavior does not occur other analysis methods are required to determine the fracture propagation or closure pressure. Superposition Analysis: The common pressure -rate analysis methods of well performance do not account for the effects of injection rate changes on the reservoir behavior. For accurate interpretation and assessment of fracture containment and injection pressure limits; these cases (including SRT) are best handled through the implementation of the multi -rate superposition principles. The principle of superposition amounts to dividing the injection history into a sequence of rate changes. The total effect of the injection on the pressure response is the additive effects of each of the rate changes. The superposition analysis is used in this report to estimate the overall skin in fractured injection. In the following sections we have provided a narrative for each of the three GNI wells and have supplied the test interpretations. www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77063, (+i) 713.532.7627 Page 1 of 14 dvantek Exhibit 8 — 2014 Step Rate Tests 490..�-- ,NTLRrtAT,ONnI BP GNI October 2014 GNI-2A SRT 2014 In July 2014 a step rate test (SRT) was conducted for well GNI-2A. In Figure 1, the injection history for well GNI-2A in 2014 is demonstrated where it is observed that after one period of solid injections; about two and a half periods of water -only injection preceded the step rate test. The well was shut-in for a period of 27 days so that the pressure had stabilized before this injection cycle. The 2014 step rate test was similar to the previous year test so that the step-down test was conducted before the step-up test. This was to prevent possible problems that would lead to difficulties in conducting the SRT test if it took several days for the injection pressure to raise and stabilize. This unusual low injection pressure response had been observed at the start of one Injection cycle for well GNi-2A in 2013. Nevertheless, the problem of low pressure response has not occurred again in any of the injection cycles that were followed in well GNI-2A and in particular in the cycle starting on 6/28/2014 that included the 2014 step rate test. 40,000 35,000 30,000 d E >0 20,000 c 0 M v 15,000 10,000 5,000 --GNI-2A Injection Volume (bbl) —GNI-2A Solids Injection (tons) GNI-2A Step Rate Test: 7/6/2014 0 1 1 1_P' ' T I ' I I I r ' 11/22/2013 1/11/2014 3/2/2014 4/21/2014 6/10/2014 7/30/2014 Time (Date) Figure 1: Injection history for well GNI-2A in 2014 4,000 3,500 3,000 e 2,500 0 V 2,000 c 0 V d 1,500 .L 1,000 500 0 9/18/2014 Figure 2 represents the raw test data from the SRT tests for well GNI-2A. The test was initiated at a rate of an average 20.7 bpm (29,750 bpd). The rate was steadily decreased in 9 consecutive steps and pressure stabilization was attempted in each step with the final step having reached a rate of 2.7 bpm (3895 bpd). After final step in the step-down test, injection was stopped for about 12 hours and then the rate was increased for 9 steps in the step-up test (the lag between step-down and step-up tests is not shown in the figure for simplicity). It appears that it has been difficult to maintain the constant rate injection in step 3- www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77063, (+1) 713.53 •7627 Page 2 of 14 4gpdvantek Exhibit 8 — 2014 Step Rate Tests N TEQNHi BP GNI October 2014 10 such that the injection rate approaches a continuously decreasing rate rather than a constant -rate injection during the last 8 steps in the step-up leg. As seen in the figure, the final rate in the step-up test reached an average of about 21.4 bpm (30810 bpd) before the well was finally shut-in. Each step lasted for an average of about 50 minutes giving a total time of about 17 hours. ---Injection Rate ♦ End Point Injection Rate Injection Pressure t End Point Injection Pressure 27 24 21 a18 m 15 cC +r O 12 41 v d r 9 6 3 0 0 100 200 300 400 500 600 700 800 900 Time (min) Figure 2: Injection pressure and rate plot for well GNI-2A 4500 4300 4100 H a 3900 d 3 3700 a c 3500 O 41 v d 3300 S 3100 2900 - 1 1 2700 1000 1100 Conventional Analysis: Figure 3 shows the conventional analysis for the GNI-2A SRT for both the step-up and step-down legs. The step-up rate test indicates flow regimes into a pre-existing and possibly damaged fracture. It is observed that in the step-up leg of the test, a bi-linear behavior in the pressure versus rate plot is realized. However, the rather low slope of the first line is an indication that the flow connects to an unsealed and existing fracture shortly after injection starts. Fracture flow, however, indicates flow resistance due to possible damage. The figure shows that the initial pre-existing fracture flow is followed by an apparent drop in the slope of pressure -rate plot at a high rate (14.6 bpm). This is an indication that either flow resistance due to internal damage or possible damage boundaries is removed or another pre-existing fracture is re -opened. However, the analyses of the falloff test that was conducted later in well GNI-2A indicated the presence of two fracture closure events so the second line in the step-up leg is most probably due to fracture flow by re -opening a second fracture (refer to the report Exhibit 9, 2014). No significant slope change is observed during fracture flows, thus indicating that the damage degree is roughly the same along the length of the fractures. www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas T7o63, (+') 713.532.7627 Page 3 of 14 dvantek Exhibit 8 — 2014 Step Rate Tests IN7ERNA7 -, BP GNI October 2014 As Figure 3 shows, the step-down test displayed an excellent agreement with the step-up tests at all steps and the two curves show similar and close trending behaviors. This response, again, reaffirms that the fracture extension during the test occurred in a pre-existing and possibly slightly healed fracture. The increase in pressure difference between the step-up and step-down tests after step 4 of step-down test can be attributed to the transient effect from previous injection steps. In addition, the fact that the pressure does not dissipate quickly in the step-down test and is above step-up pressures in the last six steps indicates formation plugging around the fracture. However, it is noted that the pressure at the end of step-down test is only about 230 psi above the end pressure in the first step of the step-up test. This agrees with the fact that after one period of solid injections, about two and a half periods of water -only injection preceded the step rate test (Figure 1). This increases the possibility that water injection has significantly flushed away mud solids deposited in the formation and inside fracture when step rate test is conducted. Finally, as seen in Figure 3, fracture does not close at the end of GNI-2A step-down rate test. Unlike the results of the previous year test, flow behavior in well GNI-2A in 2014 consists of fracture -only flows and the fact that fracture closure is not observed. o Step -Down C Step-up 4500 4300 � Q °p • 4100 c a � 3900 - N Q a a` 3700 o Pressure signature i ndicative of SSWb' v flow in a pre-existing and possibly 3300 propped -open fracture 3100 i 2900 ... 0 5 10 15 20 25 Injection Rate (bpm) L Step -Up o Step -Down 45n0 _.. .. _ . 4600- ^ L v i 4300 - f 4400 - 4100 n w 3900 i m 4200 A " V. .1, � � y 0 y` 3700 y 4000 `o Possible second fracture Fracture Flow a nsoo re -opening @ = 4290 psi 4 3600 . 3300 - pre-existing and = 14.6 bpm ( m 3100 Fracture Flow i 3600 No Fracture Closure 2900 .... .. .. 3400 �. -..... _.._.... 0 5 10 20 25 0 5 10 15 20 25 Injection Rate {bpm) Injection Rate (bpm) Figure 3: Conventional pressure versus rate for well GNI-2A www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77063, (+i) 7n3.532.7627 Page 4 of 14 4%dvantek Exhibit 8 — 2014 Step Rate Tests INT!-: Tt� t BP GNI October 2014 Superposition Analysis: Taking into account the effects of each step on the succeeding steps and applying the superposition principle the skin was estimated by matching the observed bottom -hole pressure. Results of this analysis are illustrated in Figure 4 and Figure 5. Application of the superposition technique requires input of the permeability value. In this analysis, a range of 100 to 200 mD for permeability was considered in the simulations to estimate the skin for the well. The skin value was varied until a perfect match between the simulated and the field data was reached. For the range of permeability considered in the simulations the estimated fracture skin was in the approximate range of -4.3 to 0.1. 4500 4400 4300 4200 Sir!) -a„- 4100 d a� 4000 n 3900 3800 1 i 3700 ! 1 ,fit O 0 01 p1 c Test Pressure 3600 _. _. _ ......._. ... .._ .. 0 $000 10000 15000 Simulated Pressure— _.._ 200DO 25000 30000 35000 Injection Rate (bpd) Figure 4: Superposition analysis for well GNI-2A Test Pressure - Simulated Pressure asuu 4400 i i300 - e b 6100 � c — I a000 � App ent Skin 2a 9 j 8 r la is a600 0300 n _ 4— - 41. — sri a� a4DD - fir t 0 '2 3yq 6��i 3 0600 IMD Permeebllity-300 mD 6 31. Permeability=200m0 7 3- 0 1 4 6 0 ]I 24 16 18 D 1 < 6 8 10 Time (hrs) Time (hrs) Figure 5: Pressure history match and skin for well GNI-2A TesiP essure Simulated Pressure Apparent Skin 9u 8 5 2 r 4 5 0 14 6 18 www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77063, (+1) 713.532.7627 Page 5 of 14 490dvantek Exhibit 8 — 2014 Step Rate Tests BP GNI IfJrERNATION October 2014 GNI-3 SRT 2014 In July 2014 a step rate test (SRT) was conducted for well GNI-3. Figure 6 shows the injection history for well GNI-3 in 2014 where it is observed that after two period of solid injection, almost three periods of water -only injection preceded the step rate test. The well was shut-in for a period of 27 days so that the pressure had stabilized before this injection cycle. 40,000 35,000 30,000 .Q 25,000 E 3 O c 20,000 O u 6i = 15,000 10,000 5,000 0 � 11/22/2013 --GNI-3 Injection Volume (bbl) —GNI-3 Solids injection (tons) GNI-3 Step Rate Test: 7/12/2014 4,000 3,500 3,000 v 2,500 c 2,000 in C O u 1.5w a+ 1,000 500 0 1/11/2014 3/2/2014 4/21/2014 6/10/2014 7/30/2014 9/18/2014 Time (Date) Figure 6: Injection history for well GNI-3 in 2014 In Figure 7, the raw test data from the SRT tests for well GNI-3 is presented. The injection rate increased from an average 3.1 bpm (4,510 bpd) to 24.2 bpm (34,815 bpd) in 10 steps over a period of approximately 8.5 hours during the step-up leg. The rate was then reduced to an average 2.9 bpm (4,140 bpd) in 10 steps over a period of about 7.5 hours during the step-down leg. It appears that it has been difficult to maintain the constant rate injection in steps 3-7 of the step-up test and steps 1-7 in the step-down leg such that the injection rate approaches a continuously decreasing rate rather than a constant -rate injection. www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 6 of 14 40dva ntek Exhibit 8 — 2014 Step Rate Tests BP GNI INTERNRTt4 October 2014 27 24 6 3 0 --Injection Rate ♦ End Point Injection Rate • Injection Pressure • End Point Injection Pressure 0 100 200 300 400 500 600 700 800 900 1000 Time (min) Figure 7: Injection pressure and rate plot for well GNI-3 Conventional Analysis: 4500 4300 4100 AA a 3900 d L 3 Vf 3700 a C 3500 C u d 3300 = 3100 2900 2700 1100 Figure 8 shows the conventional analysis for the GNI-3 SRT for both the step-up and step-down legs. The step-up rate test shows initially a possible mixture of matrix and a conductive fracture flow followed by re- opening a pre-existing fracture at 3760 psi. This is due to the fact that a sudden reduction in slope occurs while even a decrease in pressure is observed. Fracture flow continues until a second change in slope occurs at 9.7 bpm where pressure increases about 180 psi in a linear fashion. The pressure increase is due to a flow resistance which may originate from internal damage/plugging in the fracture or a damage boundary that has crossed the fracture. When this occurs, flow may be a combination of fracture bilinear flow and flow through the damage boundary. A third change in slope occurs at 13.1 bpm where a decrease in slope (zero slope) may indicate removal of some flow restriction due to damage. The cycle of decrease and then increase in slope is again observed starting at 15.9 bpm until the end injection rate of 24.0 bpm. It is interesting to note that from the fracture re -opening point (at 9.7 bpm) to the end of the step-up cycle, the pressure increase is only about 240 psi, indicating a fracture flow with high conductivity and not much damage. This is in agreement with the fact that almost three periods of water -only injection followed the last solid injection period (Figure 6). This increases the possibility that water injection has significantly flushed away mud solids deposited inside the fracture when step rate test is conducted. In the step-down test, pressure does not decrease quickly and is above step-up pressures at all steps, likely due to the damage beyond and around well and the fracture. Finally, as seen in Figure 8, fracture does not close at the end of GNI-3 step-down rate test. Compared with the results of the www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.5332.7627 Page 7 of 14 dvantek Exhibit 8 — 2014 Step Rate Pests BP GNI W IL INTERNgTIONgI October 2014 previous year test, flow behavior in well GNI-3 is very similar to that in 2013 test except that fracture closure was observed in 2013. A Step -Up Step -Down 4500 4300 4100 ii . ♦ ♦ e o ♦ ♦ ♦ s � ;; u r 3s�. - ♦ 6 is 0 � � C3700 a 0 0 4510 Q Pressure signature is indicative of connection 3300 to a conductive pre-existing fracture which 3100 - re -opens as injection rate increases 2900 - 0 - 10 .- 20 -. Injection Rate (bpm) 6 Step -Up + Step -Down 4500 I 4500 4110 Fracture Flow 43M -- 4300 •'. i ]90U ... ....�i... n' 39M •. X a+A © t. d Fracture Flow 35GO d 3500 Fracture Flow l.. c 3300 Fracture Re -Opening: c 3300 'r 3100!,,. Reopening pressure = 3760 psi @ 3100 ;- No Fracture Closure ' Rate = 7.1 bpm i 5 10 15 20 25 0 5 10 15 20 25 0 Injection Rate (bpm) Injection Rate (bpm) Figure 8: Conventional pressure versus rate for well GNI-3 www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 8 of 14 -1-1121 dvantek Exhibit 8 — 2014 Step Rate Tests INTERNATIDNAi BP GNI October 2014 Superposition Analysis: Figure 9 and Figure 10 show the pressure and skin simulated using the superposition principle at two different permeability values, 100 mD and 200 mD for well GNI-3 data. Again, the skin value was varied until perfect match between the simulated and the field data was reached. For the range of permeability considered in the simulations the estimated fracture skin was in the approximate range of -5.0 to -3.4. 4200 4100 aaoo ' o� �O °♦ �o °` ° ^ 3900 3500 1° ■ O� O� ° �° � 3700 j O �O a 3600 - 8 Test Pressure 3500 3400 0 • simulated Pressure E 3300 3200 0 5000 20000 15000 20000 25000 30000 35000 40000 Injection Rate (bpd) Figure 9: Superposition analysis for well GNI-3 Test Pressure _.. _...... Simulated Pressure .._... - Apparent Skin /0 Test Pressure Simulated Pressure Apparent Skin 10 4000 3900 9 8 4M 9 " 8 3840 6 5 3r00 N 6 - 5 4 a m 310D I Permeability = 300 mD .- 3 c y 3>44 Permeability = 200 mD i N 2 N 1 2 3640o ° L - O. Vol 3500 1 3500 3400 1 330D -2 -3 4 34003 -2 4 0 2 4 6 8 10 12 Time (hrs) 6 14 16 is 0 2 4 6 8 10 12 14 16 Time (hrs) 6 18 Figure 10: Pressure history match and skin for well GNI-3 www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77063, (+1) 713.532.7627 Page 9of14 4Q< �_ a n�w Exhibit 8 — 2014 Step Rate Tests WIL ' UV INTERNATIONAL BP GNI October 2014 GNI-4 SRT 2014 In August 2014, a step rate test (SRT) was conducted for well GNI-4. In Figure 11, the injection history for well GNI-4 in 2014 is shown where it is observed that after two periods of solid injection; about two and a half periods of water -only injection preceded the step rate test. The well was shut-in for a period of 27 days so that the pressure had stabilized before this injection cycle. The 2014 step rate test was modified so that, similar to the procedure in well GNI-2A, the step-down test was conducted before the step-up test. This was to prevent possible problems that would lead to difficulties in conducting the SRT test if it took several days for the injection pressure to raise and stabilize. This unusual low injection pressure response had been observed at the start of one injection cycle for well GNI-4 in 2013. Similar to well GNI- 2A, the problem of low pressure response has not occurred again in any of the injection cycles that were followed in well GNI-4 and in particular in the cycle starting on 7/26/2014 that included the 2014 step rate test. ---GNI-4 Injection Volume (bbl) —GNI-4 Solids injection (tons) 40,000 GNI-4 Step Rate Test: 8/2/2014 35,000 30,000 25,000 3 0 0 20,000 4+ V 07 15,000 10,000 5,000 0 a , �—T 11/22/2013 1/11/2014 3/2/2014 4/21/2014 6/10/2014 7/30/2014 Time (Date) Figure 11: Injection history for well GNI-4 in 2014 4,000 3,S00 3,000 fA C 2,500 N 0 2,000 C M d 1,500 = 1,000 500 0 9/18/2014 Figure 12 shows the raw test data from the SRT tests for well GNI-4 where both the step-down and step- up legs are presented. The test was initiated at a rate of an average 21.1 bpm (30,450 bpd). The rate was steadily decreased in 9 consecutive steps and pressure stabilization was attempted in each step with the final step having reached an average rate of 3.4 bpm (4,830 bpd). After final step in the step-down test, www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 10 of 14 �C�V�I�I< Exhibit 8 — 2014 Step Rate Tests INTERNATIONAL BP GNI October 2014 injection was stopped for about 12 hours and then the rate was increased for 9 steps in the step-up test (the lag between step-down and step-up tests is not shown in the figure for simplicity). It appears that it has been difficult to maintain the constant rate injection in step 3 and steps 5-10 such that the injection rate approaches a continuously decreasing rate rather than a constant -rate injection during the last 6 steps in the step-up leg. As seen in the figure, the final rate in the step-up test reached an average of about 22.0 bpm (31760 bpd) before the well was finally shut-in. Each step lasted for an average of about 50 minutes giving a total time of about 17 hours. 27 24 21 C 9 6 3 0 --Injection Rate ♦ End Point Injection Rate • Injection Pressure . End Point Injection Pressure ice' 1I I 100010. r � ' S s I T I i t I 4500 4300 4100 11 3900 v L 3 V7 3700 i a c 3500 C a 3300 3100 2900 2700 0 100 200 300 400 500 600 700 800 900 1000 1100 Time (min) Figure 12: Injection pressure and rate plot for well GNI-4 Conventional Analysis: In Figure 13, the conventional analysis for well GNI-4 for both the step-up and step-down legs is presented. The plots show a stunning resemblance with those of well GNI-2A in that a very similar bi- linear behavior in the pressure versus rate plot in the step-up leg of the test is realized while the pressures are lower in well GNI-4. Again, the rather low slope of the first line in the step-up leg is an indication that the flow connects to an unsealed and existing fracture shortly after injection starts. Fracture flow, however, indicates flow resistance due to possible damage. The figure shows that the initial pre-existing fracture flow is followed by an apparent drop in the slope of pressure -rate plot at a high rate (14.9 bpm). This is an indication that either flow resistance due to internal damage or possible damage boundaries is removed or another pre-existing fracture is re -opened in this well, as was the case for well GNI-2A. However, the analyses of the falloff test that was conducted later in well GNI-4 indicated the presence of multiple fractures (refer to the report Exhibit-9, 2014) so the second line in the step-up leg is most www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 11 of 14 A:ndvantek Exhibit 8 — 2014 Step Rate Tests INTERNATIONAL BP GNI October 2014 probably due to fracture flow by re -opening a second fracture. No significant slope change is observed during fracture flows, thus indicating that the damage degree is roughly the same along the length of the fractures. Figure 13 shows that except for the first four (4) steps, the pressure in the step-up leg is higher than the corresponding pressure in the step-down leg. In other words, the pressure dissipates quickly in the step- down test and is below step-up pressures in most steps. It is also observed that there is good agreement between the step-down and step-up legs in that the two curves show similar and close trending behaviors. This reaffirms that the fracture extension during the step-up leg occurred in a pre-existing fracture while the fracture is with high damage (low conductivity) or slightly healed. It is noted that in the last step of the step-down leg, the pressure is only about 180 psi above the first step of the step-up test. This agrees with the fact that after less than two periods of solid injections, about two and a half periods of water -only injection preceded the step rate test (Figure 11). This increases the possibility that water injection has significantly flushed away mud solids deposited in the formation and inside fracture when step rate test is conducted. Finally, as seen in Figure 13, fracture does riot close at the end of GNI-2A step-down rate test which was also the case in the 2013 test. o Step -Down L Step -Up 4500 4300 ^ aloo � G G a G O 3900 N po a3700 0 Q c � G 3500 Pressure signature is a 3300 - indicative of flow in a 3100 pre-existing fracture 2900 0 5 30 15 20 25 Injection Rate (bpm) 4 Step -Up o Step -Down 4500 4500 0300 '. Pre-existing 4300 Fracture Flow ` ^ 4100 ► = 4100 n C n c � 3900 - C � 3900 t V Fracture Flow ` 3700 G 3700 - 6 r d 3—` 350o v Fracture Flow 5 33M _ Possible Second Fracture Re -opening: = 3300 31W = 4100 psi @ Rate = 14.9 bpm '., 310C - No Fracture closure 2900 '. 0 5 10 15 20 25 Injection Rate (bpm) 2900 - - _ _ ... 0 5 . _ .. _.. ... _. _. _. . _. .. .. .. _...... _. to 15 20 25 Injection Rate (bpm) Figure 13: Conventional pressure vs. rate for well GNI-4 www.AdvantekInternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 12 of 14 40dvantek Exhibit 8 — 2014 Step Rate Tests NTEFNRT BP GNI October 2014 Superposition Analysis: Similar procedures in previous wells were used for well GNI-4. Figure 14 and Figure 15 show the pressure and skin simulated using the superposition principle at two different permeability values, 100 mD and 200 mD. Again, the skin value was varied until perfect match between the simulated and the field data was reached. For the range of permeability considered in the simulations the estimated fracture skin was in the approximate range of -4.5 to -2.2. 4400 4200 -i 40M 3a�l '^ oo O� 3600 O 3400 ° C Test Pressure • Simulated Pressure - 3200 0 5000 10000 15000 20000 25000 30000 35000 Injection Rate (bpd) Figure 14: Superposition analysis for well GNI-4 Test Pressure $m fated Pressure Apparent Skin j Test Pressure Simulated Pressure 4300 _ 13 4300 12 4200 Permeability = 200 mD 21 M. Permeability = 200 mD 1e 4100 0 410 a 4pW 2 40W L jI( N 3900 5 i � 5 3900 - 3800 3 38W 2 y 3,00 I 'i 1 32W j o Asks 36W I1 36W r 35W �'� 3 35W t � a 1— 4 5 34W - 6 3— 2 Ili 33W 0 2 < 6 8 10 12 14 16 18 20 0 2 4 6 e 10 12 Time (hrs) Time (hrs) Figure 15: Pressure history match and skin for well GNI-4 Apparent Skin www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 2157, Houston, Texas 77063, (+1) 713.532.7627 Page 13 of 14 dvantek Exhibit 8 — 2014 Step Rate Tests INTERNATIONAL BP GNI October 2014 Summary and Concluding Remarks Step rate test analyses in the three GNI wells indicate connection to pre-existing fractures in the step-up tests while fractures do not close at the end of the step-down tests. The following represents the flow characteristics and test interpretation details in each well: o Well GNI-2A • No matrix flow is interpreted from the step-up test. Flow connects to the fracture immediately after the test starts. The test analyses show the initial lire -existing fracture flow is followed by re -opening of another pre-existing fracture. This event is further validated from the pressure falloff test that was conducted after the SRT test. • The second fracture re -opens at =14.6 bpm and =4290 psi. • The fracture extension experiences resistance due to possible damage or internal plugs. No major removal of flow restriction is observed. • Unlike last year test results, fracture does not close at the end of the step-down test. o Well GNI-3 • The step-up test shows initially a possible mixture of matrix and a conductive fracture flow that is followed by re -opening a pre-existing fracture at =7.1 bpm and 3760 psi. • The fracture flow experiences resistance due to some internal plug or possible damage boundary. At two instances, removal of flow restriction is observed. • The pressure increase in the fracture flow is only about 240 psi, indicating a generally high conductive fracture. • Unlike last year test results, fracture does not ciose at the end of the step-down test. o Well GNI-4 • No matrix flow is interpreted from the step-up test. Flow connects to the fracture immediately after the test starts. • The test analyses show the initial pre-existing fracture flow is followed by re -opening of another pre-existing fracture. This event is further validated from the pressure falloff test that was conducted after the SRT test. • The second fracture re -opens at =14.9 bpm and =4100 psi. This rate is very close to the results in well GNI-2A, however, with lower pressure. • The fracture extension experiences resistance due to possible high damage or internal plugs. No major removal of flow restriction is observed. • Similar to last year test results, fracture does not close at the end of the step-down test. www.Advantekinternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 14 of 14 dvclntek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 q0rINTERNATIOkHI Exhibit 9 2014 Pressure Falloff Tests Surface Pressure falloff (SFPO) tests were performed on the three GNI wells (GNI-2A, GNI-3 and GNI- 4) during the summer of 2014. The well test data was analyzed by Advantek International using PIE pressure transient analysis software. Pressure values stated in this report are referenced to the main perforated intervals: 6557 ft TVD for well GNI-2A, 6600 ft TVD for well GNI-3, AND 6513 ft TVD for the GNI-4 well. The objective of the SPFO tests is to study the suitability of GNI wells for appropriate injection as well as the assurance for future waste disposal operations using these wells. In order to achieve this goal it is necessary to understand the injection mechanisms and identify the most appropriate behavioral model for the reservoir through type -curve analysis. Given the appropriate model, the SPFO can be used to estimate the following characteristics of the reservoir: • Hydraulic fracture dimensions • Hydraulic fracture skin • Hydraulic fracture conductivity • Reservoir permeability • Reservoir pressure • Dimensions of the effective reservoir / distance to flow boundaries Summary of the Analyses Results for 2013 SPFO Tests: Based on the availability of models in software PIE, the following four type curve models were used to analyze pressure falloff test data in each well: • ICVF - Infinite Conductivity Vertical Fracture model • FCVF - Finite Conductivity Vertical Fracture model • RCH -Radial Composite Homogeneous reservoir model • RCDP - Radial Composite Double -Porosity Reservoir model Best match for the 2013 PFO tests for each well was obtained as: • Well GNI-2A: RCDP and RCH models • Well GNI-3: RCDP and RCH models • Well GNI-4: RCDP model It appears that the Radial Composite model (either with or without Double -Porosity behavior) represents at least part of the true behavioral characteristics of the reservoir sections around each well. These models in conjunction with a hydraulic fracture are not available in software PIE. However, standard diagnostic analyses and the use of stand-alone fracture models indicate the existence of hydraulic fractures in the injection operations. This is further confirmed from the Step Rate tests performed in the same wells. Strong water hammer effect was observed at shut-in in wells GNI-2A and GNI-4. This prevented obtaining better fits especially at early times. www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. z57, Houston, Texas 77o63, (+i) 713.5332.762.7 Page 1 of 25 dva ntek _ Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 INTERNRTIUNRL Based on the results of 2014 tests, the following conclusions can be made about the extent of hydraulic fractures and reservoir features: Well GNI-2A: The combined effects of fracturing and solid deposition has created a composite reservoir system in which the inner zone radius is approximately 395 ft and has a higher permeability than the permeability of the reservoir outer zone (virgin) which is estimated to be about =150 mD. This system is available to take additional slurry allowing the GNI operation to continue in this well. Well GNI-3: The combined effects of fracturing and solid deposition has created a composite reservoir system in which the inner zone radius is approximately 250 ft and has a higher permeability than the permeability of the reservoir outer zone (virgin) which is estimated to be about =150 mD. This system is available to take additional slurry allowing the GNI operation to continue in this well. Well GNI-4: The combined effects of fracturing and solid deposition has created a composite reservoir system in which the inner zone radius is approximately 455 ft and has a lower permeability than the permeability of the reservoir outer zone (virgin) which is estimated to e about �240 mD. This system is available to take additional slurry allowing the GNI operation to continue in this well. Detailed results with graphs and tables are presented in the following sections for each well where comparisons are also made with the results of the two previous years. Discrepancies stem most probably from lack of simultaneous match for both pressure -derivative match and history match (multi -rate injection behavior). Only the best fit models are shown in the figures throughout the report while the remaining plots obtained from other models used are shown in the Appendix. Test Data Preview In the first step of the analyses, the measured data from all falloff tests must be inspected, integrated, and required parameters calculated. For complete analysis, the shut-in period has to be sufficiently long enough to overcome wellbore and fracture storage effects. It is necessary to convert the provided surface pressure measurements (WHIP) into bottomhole pressure (BHIP) to minimize noise in the data and to allow proper interpretation of the reservoir characteristics. To achieve this, pressure data from before and after shut-in periods must be integrated into one consistent set of input data. The bottomhole pressure is calculated from the wellhead pressure by adding borehole hydrostatic head and subtracting the frictional pressure (Fp) as shown in the following formula: BHIP = WHIP + 0.052 p Z - Fp Where p is the well fluid density in lb/gal, Z is the injection depth (perforation depth) in ft, and units for pressures are psi. The frictional pressure drop is a function of the injection rate before shut-in. To calculate Fp, the following correlation formula derived by BP is used for the BP-GNI wells: Fp = 0.2667 QZ + 0.6037 Q where Q is the injection rate in bpm. www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 2 of 25 dvantek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI �— October 2014 INTERNATIONAL Figure 1-3 show the recorded raw data as well as the calculated BHIP before and after shut-in for wells GNI-2A, GNI-3 and GNI-4. The plots show injection rate, wellhead pressure, and the calculated bottom -hole pressure. The wellhead temperature as well as shut-in temperature variation is also shown in the figures. For each well, the dates indicating start and finish of data recording as well as the shut-in date are included in the corresponding figure. These figures show relatively stabilized injection rate and pressure data for a period of approximately 25 hours prior to shut-in. However, a sudden drop in pressure is observed in about 10 hours before shut-in in well GNI-2A. The after shut- in data recording is also observed for a period of six (6) days in each well until the reservoir pressure has stabilized. —Wellhead Pressure—Bottomhole Pressure --Total Injection Rate —WHIT —SI-Temp 5000 , --- -- i 100 4500 4000 3500 N 3000 O. v 2500 V1 N a` 2000 1500 1000 500 90 80 a m 70 B a 60 O' 50 a 40 y 30 c O u ' 20 C 10 0 i r= r -- -----r-- - 0 0 s0 100 150 200 250 300 350 400 450 500 6/29/2014 Elapsed Time (hr) 7/18/2014 Figure 1: Historical data for July 2014 pressure falloff test in well GNI-2A www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 3 of 25 4qNrdva ntek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI .....-� INTF RNATIONAL October 2014 —Wellhead Pressure —Bottomhole Pressure ---Total Injection Rate —WHIT —SI-Temp GNI-3 Data Well 4500 I a0 _ 4000 80 +� 2 3500- 70 R 3000 60 d 0. E� '' 2500 U 50 - N 0. p 2000 1 Shut-in Cate: 40 d, 7/19/2014 M cc 1000 i,, s 1�,r.Y IJ{Y�� rl I 20 Soo t ( { 10 1 0 ,——r---r--r--f- 0 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 ' 7/22/2014 Elapsed Time (hr) 7/25/2014 Figure 2: Historical data for July 2014 pressure falloff test in well GNI-3 i —Wellhead Pressure —Bottomhole Pressure - Total Injection Rate —WHIT —Si-Temp 5000 4500 4000 3500 :N 3000 O. 2500 N G1 a 2000 1500 1000 500 0 100 90 80 LL uJ L 70 y3 C 60 E N so E a 40 y A dX 30 c O u 20 v 10 0 0 50 100 150 200 250 300 350 400 450 500 7/26/2014 Elapsed Time (fir) 8/15/2014 Figure 3: Historical data for August 2014 pressure falloff test in well GNI-4 www.Advantekinternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 4 of 25 oantek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 44s— 11JTERNATIONAL Input Parameters for PFO Analysis The time variations of bottomhole pressure and injection rate values, which were integrated from before and after shut-in, were inputted into software PIE for pressure falloff analyses. Other input data used in the analyses are related to the reservoir and fluid properties and are listed in Table 1. Table 1: Reservoir and fluid properties Parameters Value Fluid Volume Factor 0.995 Fluid Viscosity (cp) 1.0 Fluid Compressibility (10-6 psi) 2.94 Water Compressibility (10-6 psi) 2.94 Porosity (%) 32 Water Saturation (%) 100 Net Thickness (ft) 100 -6 -1 Rock Compressibility (10 psi ) 6.70 Wellbore Radius (in) 6.125 Methods of Analysis Two common types of available analyses in software PIE were utilized to analyze the data as follows: Pressure and Pressure Derivative Curve Analysis The pressure (Ap) and pressure derivative curves usually gives the basic knowledge about the reservoir and the flow characteristics. The primary purpose of the pressure data plot is to define the overall pressure -change in the analysis and demonstrate the characteristic shape as related to a type - curve. Also, pressure data with an initial unit slope indicates wellbore storage effect which is not representative of the reservoir behavior. This is a result of a wellbore storage flow which can be related to draining or filling the fixed wellbore volume. Both pressure and pressure derivative curves are used to obtain some primary estimates for wellbore storage, permeability and fracture length. Also, the separation between the derivative and the Op data is related to the total skin of the test. In addition to these basic characteristics, more interesting shapes are present in the derivative curve. Other than a unit slope, which is indicative of the wellbore storage effect, other more common examples are a 1/2 slope for linear flow and a 1/4 slope for bi-linear flow. Type -Curve Analysis After the initial pressure and derivative analysis of the test data, a type -curve analysis is carried out. The estimated parameters in the first step above can then be used in this more rigorous method of analysis to attain a best match for the field data, and thus obtain better estimates for all reservoir and fracture properties. Several type -curve models are available in software PIE to investigate the pressure falloff data. For the analyses of the GNI wells, four models were selected as previously noted in the Summary section. In the following sections, falloff analyses results are described for each of the three GNI wells separately. www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 5 of 25 dva ntek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 40INTERNATIONAL Well GNI-2A PFO Analyses Results Figure 4a shows the log -log plot of the pressure drop and its derivative versus time for well GNI-2A. As seen in the figure, water hammer effect at shut-in has masked the unit -slope in this well. The unit slope is usually observed in the early portion of the pressure and derivative curve. A picture of the pressure variation immediately after shut-in with the water hammer event in well GNI-2A is given in the Appendix. The water hammer effect results in difficulties in the type -curve matching and the goodness of fits. However, the analysis was improved by isolating the effect of water hammer from the matching process. Half -slope and quarter -slope trends in the pressure and derivative plots are observed which indicate the existence of hydraulic fractures with linear formation flow and a mixed fracture and formation flow (bilinear flow). Compared with previous years' tests, the derivative plot in wall C;Nl-?A shows a second main fracture closure. The existence of a second main fracture is in agreement with the results of 2014 Step Rate Test where a second fracture opening was realized (refer to the report Exhibit 8, 2014). Also, Figure 4a, represents the best match in the type -curve analysis for the well GNI-2A using the Radial Composite Double -Porosity (RCDP) model for both pressure and the derivative curves while the history match for this model is given in Figure 4b. The figures indicate a fair match for well GNI- 2A data using this model. The plots for the match using other three model types are left to the Appendix. The results of all analyses are summarized in Table 2 where they are compared with the results obtained in the past two years. Note that for the RCH and RCDP models parameters mechanical and global skins are recorded. The term "Global Skin" means the net effect of all flow restrictions or enhancements between the wellbore and the reservoir. For these models, the "Global Skin" will have two parts: the first is due to the permeability change in the near wellbore area (mechanical skin), and the second is due to flow restriction/enhancement of the inner -zone permeability. Although the term "mechanical skin" reflects reduction in permeability (positive skin) from mechanical factors such as plugging of perforations or formation matrix, this parameter in software PIE output for RCH and RCDP models may be a negative value representing near wellbore permeability enhancement that has overcome the real mechanical skin. www.AdvantekInternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 6 of 25 40 dvantek �— INTEONHTIONAI. a b Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 2014N7/Y&0350: 300 400. Figure 4: GNI-2A best match type -curve model (RCDP): a) Differential pressure Dp and derivative match. In the plot, Delta-T represents time after shut-in (hr) while the vertical axis shows differential pressure after shut-in (psi) and its logarithmic derivative (psi/bpd). b) History match. In the plot, the horizontal axis represents elapsed time while the vertical axis shows injection pressure (psi). www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 7 of 25 qq�dva ntek Exhibit 9 - 2014 Pressure Falloff Tests IN7ERNAiIONA+ Table 2: Well GNI-2A analvsis results and historv* BP GNI October 2014 Year 2012 2013 2014 Type Curve ICVF I FCVF RCH I RCDP ICVF FCVF RCH RCDP ICVF FCVF RCH I RCDP Mndnl wellbore Storage 1.2 1.2 0.6 0.9 0.08 0.08 0.07 0.09 0.02 0.21 0.54 0.59 (bbls/psi) Permeability 120 120 150 254 155 155 is0 150 150 150 150 150 (mD) Fracture Half 380 380 140 170 145 161 Length (ft) Fracture Skin I 0.0s I I I I 0.8s 0.40 I I 0.0 0.0 Fracture Conductivity Inf. 600000 Inf. 60000 Inf. 200000 f-.Il 4l 11111J I l� Inner Radius 340 397 340 39s 523 522 (ft) Permeability, 1500 1560 425 2480 200 200 Inner (mD) Skin 6.0 5.8 -1.1 9.8 -4.6 -4.5 (Mechanical) Skin (Global) .5.3 -4.6 -4.6 -5.7 -5.2 5.1 1 ! F Reservoir 2915 2900 2930 3010 2950 2950 2950 3050 3030 3030 3030 3030 Pressure (psi) * The box in yellow color represents the best match model The effect of additional parameters w and A in RCDP model (compared to RCH) is not significant A close examination of the match plots using the four models and comprehensive review of the results given in Table 2 lead to the following conclusions for well GNI-2A: • RCDP and RCH models provide a fair match for pressure, derivative, and injection history for well GNI-2A pressure falloff test data. ICVF and FCVF models provide a poor match for the general trends in pressure, derivative, and injection history data. • The double -porosity behavior develops due to a network of secondary fractures that are initiated around the main fractures. However, the improvement in the RCDP model match over RCH is not significant. This may be because the secondary fractures do not contribute much to the overall porosity of the inner zone. • Pressure transient analyses suggest that the injection operations in well GNI-2A may behave as slurry flow through two main fractures into the reservoir that has evolved to consist of two zones, each with different reservoir and flow characteristics. The inner zone has reservoir characteristics that are different from that of the outer virgin zone due to fracturing (primary and secondary) and deposition of solids inside the fractures and into the rock pores near wellbore and in the vicinity of the fractures. • The virgin reservoir permeability estimations from composite models and fracture models are comparable with 2013 results. The virgin reservoir permeability appears to be approximately 150 mD. www.Advantelcinternati ona 1. com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 8 of 25 dvantek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 INTERNATIONAL • Compared with the last year results, inner zone permeability shows a decrease from 2480 mD (RCDP model) in 2013 to 200 mD (RCDP model) in 2014, possibly due to extreme damage effects in 2014. This decrease is also seen from RCH model results. The predicted inner permeability represents a combined and average permeability effect produced by both rock and secondary fracturing to fit the model. The large reduction in the inner zone permeability is in agreement with the fact that RCDP model does not show much improvement in curve matching over the RCH model. • The inner zone for well GNI-2A shows negative mechanical skin (-4.5) representing near wellbore permeability enhancement. The global skin is also negative (approximately -5.1) and indicative of an overall permeability enhancement effect of fracturing despite extreme damage in the inner zone. • Compared with the last year results, inner zone radius (RCDP model) shows an increase from 395 ft. to 522 ft. • Fracture models suggest that the length of the hydraulic fracture is in the range of 290-300 ft. • The best estimate for reservoir pressure is approximately 3030 psi. • In summary, the results of 2014 PFO test confirms the previously assumed conceptual model for well GNI-2A in which fracturing and solid deposition effects have created a reservoir system with an inner zone of approximately 520 ft. and a permeability of 200 mD. The outer zone virgin reservoir permeability is 150 mD and the composite system is available to take additional slurry allowing the GNI operation to continue in well GNI-2A. For comparison purposes, recent downhole measurement in well GNA-2A [following the shut-in period of nine (9) days] shows that the current reservoir pressure is 3092 psi, which indicates an increase of about 45 psi compared to the measurement in 2013. The estimated reservoir pressure from type -curve analyses using the RCDP model is 3030 psi. The estimated reservoir pressure shows a decrease of about 20 psi compared to the estimated value in 2013. Well GNI-3 PFO Analyses Results In Figure 5a, the log -log plot of the pressure drop and its derivative versus time for well GNI-3 is shown where half -slope and quarter -slope trends in the pressure and derivative plots are recognizable and indicate the existence of a hydraulic fracture. The half -slope for the linear formation flow appears for a short period in the middle part of the derivative plot but the slope of the pressure curve at later times is very close to a quarter -slope, indicating the existence of a hydraulic fracture and a mixed fracture and formation flow (bilinear flow). As the figure shows, the unit -slope (indicating the wellbore storage effect) is not observed in the data plots. A picture of the shut-in pressure variation immediately after shut-in for well GNI-3 is given in the Appendix where it is observed that the water hammer event is not significant in well GNI-3. RCDP and RCH models provided a good match for pressure, derivative, and injection history for well GNI-3 pressure falloff test data, suggesting the existence of a hydraulic fracture in a dual mobility system. The results of type -curve analysis using RCDP model is shown in Figure 5a and Figure 5b where the match for both pressure -derivative curves and the history are given. It is observed that the general trend in the plots of the simulated model agrees well with the field data. The ICVF and FCVF fracture models provided a poor match for the derivative plot. The plots for the match using other three model types are presented in the Appendix. The results of all analyses for well GNI-3 are summarized in Table 3 where they are compared with the results obtained in the past two years. The www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 9 of 25 dvantel< Exhibit 4 - 2014 Pressure Falloff Tests BP GNI .... October 2014 40INTERNATIONAL definitions for parameters "Global Skin" and "Mechanical Skin" recorded in the table are previously given in the results section for well GNI-2A. Unit Slope ��" Hal(Slope -IW Slops m' 10 10 10' 100 101 le DeXa-T (hr) Alaska GNI-03 PFO a 201410725-0000: Oil I e � e tj C= tk* � 8 0. 60. 100, 150. 200. 250 . - 300. b Figure 5: GNI-3 best match type -curve model (RCDP): a) Differential pressure Dp and derivative match. In the plot, Delta-T represents time after shut-in (hr) while the vertical axis shows differential pressure after shut-in (psi) and its logarithmic derivative (psi/bpd). b) History match. In the plot, the horizontal axis represents elapsed time while the vertical axis shows injection pressure (psi). w-ww.Advantelclnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 10 of 25 dvantek Exhibit 9 - 2014 Pressure Falloff Tests 4§0�..�- INTCftNATIONAL Table 3: Well GNI-3 analysis results and history* BP GNI October 2014 Year 2012 2013 2014 Type Curve ICVF FCVF RCH RCDP ICVF FCVF RCH RCDP ICVF FCVF RCH RCDP Model Wellbore Storage 0.05 0.01 0.03 0.01 0.10 0.10 0.08 0.08 0.50 0.50 0.92 0.80 (bbls/psi) Permeability 100 100 150 150 115 115 150 150 80 80 150 150 (mD) Fracture Half 300 300 270 270 150 154 Length (ft) Fracture Skin 0.3 0.60 0.50 0.10 0.10 Fracture Conductivity Inf. 77890 Inf. 260000 Inf. 176200 (mD-ft) Inner Radius 350 350 350 350 250 250 (ft) Permeability, 600 600 780 840 964 1000 Inner (mD) Skin -2.2 -2.4 10.3 -9.9 -7.8 -8.0 (Mechanical) Skin (Global) -5.3 -5.4 -16.3 -16.4 -15.9 -16.0 Reservoir 2890 2900 2970 2950 2900 2900 2900 2900 2930 2930 3000 :3000 Pressure (psi) * The box in yellow color represents the best match model Using the table of results and plots of type curve matching and comparison with last year results, the following conclusions from pressure falloff analyses in well GNI-3 can be made: • RCDP and RCH models provide a good match for pressure, derivative, and injection history for well GNI-3 pressure falloff test data. The ICVF and FCVF fracture models provide a poor match for the derivative plot. • The double -porosity behavior may have developed due to a network of secondary fractures that are initiated around the main fractures. • The matches obtained in 2014 are superior to those of 2013 due to the fact that the effect of water hammer is not significant in 2014 while it affected the test analyses and matching fitness in 2013. • Pressure transient analyses suggest that the injection operations in well GNI-3 may behave as slurry flow through a main fracture into the reservoir that has evolved to consist of two zones, each with different reservoir and flow characteristics. The inner zone has reservoir characteristics that are different from that of the outer virgin zone due to fracturing (primary and secondary) and deposition of solids inside the fractures and into the rock pores near wellbore and in the vicinity of the fractures. • The virgin reservoir permeability estimations from composite models are comparable with 2013 results. The virgin reservoir permeability appears to be approximately 150 mD. www.Advantekinternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 11 of 25 4%ALVdvantek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI _ October 2014 iAT[RfdAT10MAi • Compared with the last year results, inner zone permeability shows an increase from 840 mD (RCDP model) in 2013 to 1000 mD (RCDP model) in 2014, either due to secondary fracturing effects or better curve fitness in 2014. The predicted inner permeability represents a combined and average permeability effect produced by both rock and fracturing to fit the model. • The inner zone for well GNI-3 shows negative mechanical skin (-8.0) representing near wellbore permeability enhancement. The global skin is also negative (approximately -16.0) and indicative of an overall permeability enhancement effect of fracturing despite damage in the inner zone. • Compared with the last year results, inner zone radius estimation (RCDP model) shows a decrease from approximately 350 to 250 ft. This is most probably due to the better matching in 2014 as noted in item 3 above. • Fracture models suggest that the length of the hydraulic fracture is in the range of 300-308 tr • The best estimate for reservoir pressure is approximately 3000 psi. • In summary, the results of 2014 PFO test confirms the previously assumed conceptual model for well GNI-3 in which fracturing and solid deposition effects have created a reservoir system with an inner zone radius of approximately 250 ft. and a permeability of 1000 mD. The outer zone virgin reservoir permeability is 150 mD and the composite system is available to take additional slurry allowing the GNI operation to continue in well GNI-3. For comparison purposes, recent downhole measurement in well GNI-3 (following the shut-in period of 11 days) shows that the current reservoir pressure is 3089 psi, indicating an increase of about 25 psi compared to the measurement in 2013. The estimated reservoir pressure from best match models is about 3000 psi which shows an increase compared with last year estimate but is less than the measured value. Well GNI-4 PFO Analyses Results Figure 6a shows the log -log plot of the pressure drop and its derivative versus time for well GNI-4 where similar trends as in wells GNI-2A and GNI-3 can be recognized in this well. As the figure shows, the unit -slope (indicating the wellbore storage effect) is masked in this well due to the effect of water hammer event. A picture of the pressure variation immediately after shut-in with the water hammer event in well GNI-4 is given in the Appendix. The water hammer effect results in difficulties in the type -curve matching and the goodness of fits. However, the analysis was improved by isolating the effect of water hammer from the matching process. Compared with previous years' tests, the derivative plot in well GNI-4 shows the existence of a second and a third main fracture in this well. Referring to Figure 6a, clear half -slopes are recognized at three periods on the derivative curve which are followed by a drop in the derivative, indicating the occurrence of multiple hydraulic fracture closing. Also, a very close quarter -slope coincidence with the first half -slope period is observed on the pressure curve which shows that the flow in the hydraulic fracture is bi-linear. The existence of more than one main fracture is in agreement with the results of 2014 Step Rate Test where a second fracture opening was realized (refer to the report Exhibit 8, 2014). Also, Figure 6a represents the best match in the type -curve analysis for well GNI-4 using the Radial Composite Double -Porosity (RCDP) model for both the pressure and the derivative curves while the history match for this model is given in Figure 6b. The figures indicate a good match for well GNI-4 data using this model. The plots for the match using the other three model types (RCH, ICVF, and FCVF) are left to the Appendix where it can be observed these models provide unacceptable matches www.Advantekinternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 12 of 25 4442Ldva ntek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI Na .,�.. October 2014 INTERNATIONAL for the derivative. The results of all analyses are summarized in Table 4 where they are compared with the results obtained in the past two years. The definitions for parameters "Global Skin" and "Mechanical Skin" recorded in the table are previously given in the results section for well GNI-2A. a I�i Unit Slope ��' i Half $lope I!4 Slopc 10' 10 10"2 10" 100 101 101 Deke T (hr) Alaska GNI-04 PFO al Comnosi to Double -Porosity Reservoitf P. S.5.1 20091=8.0749: Olt to i i 0. too. 2W. 300 000, b Figure 6: GNI-4 best match type -curve model (RCDP): a) Differential pressure Dp and derivative match. In the plot, Delta-T represents time after shut-in (hr) while the vertical axis shows differential pressure after shut-in (psi) and its logarithmic derivative (psi/bpd). b) History match. In the plot, the horizontal axis represents elapsed time while the vertical axis shows injection pressure (psi). www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.5332.7627 Page 13 of 25 dvantek Exhibit 9 - 2014 Pressure Falloff Tests INTERNATIONAL Table 4: Well GNI-4 analysis results and history* RP GNI October 2014 Year 2012 2013 2014 Type Curve ICVF FCVF RCH RCDP I ICVF FCVF RCH RCDP ICVF FCVF RCH RCDP Mnrlal Wellbore Storage 0.21 0.20 0.21 0.20 0.07 0.07 0.07 0.09 0.05 0.04 0.01 0.10 (bbls/psi) Permeability 180 200 190 240 190 200 190 240 200 200 240 240 (mD) Fracture Half 50 200 50 50 50 50 Length (ft) Fracture Skin I 0.48 I I I 0.50 I 0.30 I i I 0.30 0.08 Fracture Conductivity Inf. 10000 Inf. 70000 Inf. 70000 (m.D s.) Inner Radius 350 320 740 455 455 455 (ftj Permeability 290 55 250 i20 177 120 Inner (mD) Skin -1.9 -5.3 -2.0 -4.1 .3.9 -4.4 (Mechanical) Skin (Global) -3.5 -1.5 -3.3 -1.4 I -2.9 -2.0 i i f i i P 6 9 Reservoir Pressure 2850 2890 3000 3040 2850 2900 3040 3070 2970 2970 3000 3000 (psi) * The box in yellow color represents the best match model Based on the table of results and plots of type curve matching using four models, the following conclusions from pressure falloff analyses in well GNI-4 can be made: • RCDP model shows superiority to other models and provides good match for pressure, derivative, and injection history for well GNI-4 pressure falloff test data. Other models (RCH, ICVF, and FCVF) provide poor matches for the derivative. The double -porosity behavior may have developed due to a network of secondary fractures that are initiated around the main fracture. • Pressure transient analyses suggest that the injection operations in well GNI-4 may behave as slurry flow through multiple main fractures into the reservoir that has evolved to consist of two zones, each with different reservoir and flow characteristics. The inner zone has reservoir characteristics that are different from that of the outer virgin zone due to fracturing (primary and secondary) and deposition of solids inside the fractures and into the rock pores near wellbore and in the vicinity of the fractures. • The virgin reservoir permeability estimations from composite models and fracture models are comparable with 2013 results. The virgin reservoir permeability is best estimated from the RCDP model to be approximately 240 mD. • Compared with the last year results, inner zone permeability has not changed (RCDP model) in 2014 and is estimated to be approximately 120 mD. Unlike other two wells, in the dual www.Ad�anteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 14 of 25 41CJadvantek_ Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 INTFWNATIONAI composite zone system of well GNI-4 the inner zone has a lower permeability than the outer zone due to extreme damage accumulation as a result of solid deposition inside and around the fracture in the inner zone. The predicted inner permeability represents a combined and average permeability effect produced by both rock and fracturing to fit the model. • The inner zone for well GNI-4 shows negative mechanical skin (-4.4) representing near wellbore permeability enhancement. The global skin is also negative (approximately -2.0) and indicative of an overall permeability enhancement effect of fracturing despite extreme damage in the inner zone. • Compared with the last year results, inner zone radius has not changed and is equal to 455 ft. • The best estimate for reservoir pressure is approximately 3000 psi. • In summary, the results of 2014 PFO test confirms the previously assumed conceptual model for well GNI-4 in which fracturing and solid deposition effects have created a reservoir system with an inner zone of approximately 455 ft. and a permeability of 120 mD. The outer zone virgin reservoir permeability is 240 mD and the composite system is available to take additional slurry allowing the GNI operation to continue in well GNI-4. For comparison purposes, recent downhole measurement in well GNI-4 (before the injection cycle began) shows that the current reservoir pressure is 3063 psi, indicating an increase of about 22 psi compared to the measurement in 2013. The estimated reservoir pressure from type -curve analyses using the RCDP model is 3000 psi which shows a decrease of about 70 psi compared to the estimated value in 2013. The discrepancy between the estimated and measured values is most probably due to the complexity of the flow behavior in this well due to the existence of multiple fractures and the fact that a reservoir model with no fracture (RCDP) provided the best match that fits well the derivative curve only for the first fracture flow period. www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 177o63, (+i) 713.532.7627 Page 15 of 25 4qAdvantek Exhibit 9 - 2014 Pressure Falloff Tests raaINTERNATIONAL Appendix Water Hammer Events at Shut-in in GNI Wells Water Hammer Effect at Shut-in in Well 4150 4900 also � 410D a6�3 4p0f1 3950 339.8 339.81 339.81 319.83 3-M 339.85 339.tl8 339,97 334.88 339.35 Elapsed Tune (hr) Water Hammer Effect at Shut-in in Well GNI-3 —B4tt4mF4k rresw•. law a3o9 4M I gssa - 4100 4050 40p0 I6/.95 I88 i89.03 20.1 IW.Is 1a11 189.35 1".3 r Elapsed Time (hr) i Water Hammer Effect at Shut-in i n Well GN1 4 4M0 ...—tlWromn4k rres,we 4150 4100 r1 4USU W g000 6 3950 aavu 3tlS0 343.75 343.8 343.RE 343.tl4 iM.0 343.88 Elapsed Time (hr) www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 BP GNI October 2014 Page 16 of 25 45V44-�NL GNI-2A Type Curve Models GNI-2A - Radial l I a Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 Reservoir (RCN) Model 10.2 10' 10p 101 10� Delte-T (hr) Alaska GNI-02A PFO lmoaeneous Reservoir RCH Model results in fair match for pressure, derivative, and history data b 2014107260350 011j 0, 100. 200. 300. 400. I www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 2517, Houston, Texas 717o63, (+1) 713.532.7627 Page 17 of 25 4dVa, ntek Exhibit 9 - 2014 Pressure Falloff Tests INTERNATIONAL a GNI-2A — Infinite Conductivity Vertical Fracture (ICVF) Model I b � Daft.-T (nr) Alaska GNI-02A PFO Infinite Conductivity Vertical Fracture BP GNI October 2014 ICVF Model results in poor match for pressure, derivative, and history data 2D14Q7r2S4=: OIL 0. 100. 200. 300. 400 b www.AdvantekInternational.corn 33oo S. Gessner Rd., Ste. 257, Houston, Texas T7o63, (+i) 713.532.7627 Page 18 of 25 4444dva ntek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI .._.. October 2014 IATERNATION0.l a GNI-zA — Finite LoncluctiyIty Vertical Fracture 1FCVF) MOCel 101 o' ion o 100 101 IC? DeM-T (Ix) Alaska GNI-02A PFO ond� 'vi v VP ial F�ac" - FCVF Model results in poor match for pressure, derivative, and history data b 2014/07280750 OI 1 -1 i I✓��,�� llAlrMli. �" ` o i 0 0. too 200. 300. 400. www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 19 of 25 Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 GNI-3 Type Curve Models RCH Model results in good match for pressure, derivative, and history data 2014wr251 00 OI i 0. So. 100. 150. 200. 250. 300. www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 Page 20 of 25 dvantek Exhibit 9 - 2014 Pressure Falloff Tests 440A,, 14U IL ..� INiERNAT10NAl b GNI-3 — Infinite Conductivity Vertical Fracture (ICVF) Model IX b IV 10' 1a' --- 10' 10) 10' 10� Delta -Tr) Alaska GNI-03PFO Infinite Conductivity Vertical Fracture ICVF Model results in poor match for derivative plot 2014Wr&=: OI D. 50. 100. 150. iW. M. 0W. www.AdvantekInternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532.7627 BP GNI October 2014 Page 21 of 25 41gdvantek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI -F October 2014 INTERNATIONAL FCVF Model results in poor match derivative plot 201I/071254=: OR o { - +I } 0. 50" 100. ,50. 200. 250. 300. www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 22 of 25 44advantek NU IL INTERNATIONAL GNI-4 Type Curve Models Exhibit 9 - 2014 Pressure Falloff Tests BP GNI October 2014 RCH Model results in poor match for derivative plot 20=9125-m4e: a I 8 0. 100 200 300. 400. www.Advanteklnternational.com 33oo S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 23 of 25 dvantek .S iNTE RNATWNRIAL . a Exhibit 9 - 2014 Pressure Falloff Tests GNI-4 — Intinite Conductivity vertical Fracture (ICVF) model b Dana-r(M) Alaska GNI-04 PFO Tnfinite Conductivily V r al Fra ICVF Model results in poor match for derivative plot I b BP GNI October 2014 www.Advantekinternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+1) 713.532-7627 Page 24 of 25 dvantek Exhibit 9 - 2014 Pressure Falloff Tests BP GNI 4%'AOctober 2014 INTERNAiIONAI GNI-4 — Finite Conductivity Vertical Fracture (FCVF) Model z a Deft -T (nr) Alaska GNI-04 PFO Finite Conductivity Vertical Fracture FCVF Model results in poor match for derivative plot b www.Advanteklnternational.com 3300 S. Gessner Rd., Ste. 257, Houston, Texas 77o63, (+i) 713.532.7627 Page 25 of 25 O 01 /01 /13 01/31/13 03/02/13 04/02/13 05/02/13 06/02/13 07/02/13 08/02/13 09/01 /13 10/02/13 11/01/13 12/01/13 01 /01 /14 01 /31 /14 03/03/14 04/02/14 05/03/14 06/02/14 07/03/14 08/02/14 09/02/14 10/02/14 11 /01 /14 12/02/14 01 /01 /15 A O Daily Average Pressure psi O O O O O O O O O O A CO N N N W O O N O O -Ch. O N O O O O O O Injection Temperature F m k a 0 Cr Z N O a CD N c CD O Daily Average Pressure psi N A 0) w O N A O 00 O O O O O O O O O O 01/01/13 01/31/13 03/02/13 04/02/13 05/02/13 06/02/13 07/02/13 08/02/13 09/01/13 10/02/13 11/01/13 12/01/13 01/01/14 01 /31 /14 03/03/14 04/02/14 05/03/14 06/02/14 07/03/14 08/02/14 09/02/14 10/02/14 11/01/14 12/02/14 01/01/15 O O O N 0) O M N C) O O O O O O O Injection Temperature F 1 N O O 01 /01 /13 01 /31 /13 03/02/13 04/02/13 05/02/13 06/02/13 07/02/13 08/02/13 09/01 /13 10/02/13 11/01/13 12/01/13 01 /01 /14 01 /31 /14 03/03/14 04/02/14 05/03/14 06/02/14 07/03/14 08/02/14 09/02/14 10/02/ 14 11/01/14 12/02/14 01 /01 /15 Daily Average Pressure psi � 6) CO O N O O O O O M OD O O O O O O kM MM-MMM 'L -p O A OD - N N N W CDO O N O) O A OD N O O O O O O Injection Temperature F #2 Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Pt. McIntyre Oil Pool, Pt. McIntyre Oil Field Niakuk Oil Pool, Prudhoe Bay Field West Beach Oil Pool, Prudhoe Bay Field Proposed Amendment of Pool Rules and Area Injection Order BP Exploration (Alaska) Inc., by application dated September 19, 2012, has requested that Conservation Orders Number 317B (C0317B), 311B (C0311B), and 329.05 (Corrected) (C0329), which establish pool rules governing development of the Pt. McIntyre Oil Pool, Pt McIntyre Oil Field, and the Niakuk Oil Pool and West Beach Oil Pool, Prudhoe Bay Field respectively and Area Injection Order No. 4E (AI04E) be amended to expand the Affected Area of C0317B and AI04E and contract the Affected Area of C0311B and C0329. The AOGCC has tentatively scheduled a public hearing on this application for November 13, 2012 at 9:00 a.m. at the Alaska Oil and Gas Conservation Commission, at 333 West 71h Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on October 23, 2012. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after October 26, 2012. In addition, written comments regarding this application may be submitted to the Alaska Oil and Gas Conservation Commission, at 333 West 71h Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on November 8, 2012, except that, if a hearing is held, comments must be received no later than the conclusion of the November 13, 2012 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 November 9, 2012. ehyA: Foerster Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE ADVERTISING ORDER NO. /t►O�o1�G��_1 /�4_019 M SEE BOTTOM FOR INVOICE ADDRESS F R 0 M AOGCC 333 W 7th Ave, Ste 100 Anchorage, AK 99501 AGENCY CONTACT Jody Colombie DATE OF A.O. September 28, 2012 PHONE PCN DATES ADVERTISEMENT REQUIRED: ASAP THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. o Alaska Journal of Commerce 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 SPECIAL INSTRUCTIONS: Type of Advertisement SEE ATTACHED SEND INVOICE IN TRIPLICATE TO I AOGCC, 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 PAGE 1 OF 2PAGES TOTAL OF ALL PAGES$ REF TYPE I NUMBER AMOUNT DATE COMMENTS 1 VEN 2 ARD 02910 FIN AMOUNT SY CC PGM LC ACCT FY NMR DIST LIQ 1 12 02140100 73451 2 REQUISITI N D Y: DIVISION APPROVAL: 02-902 (Rev. 3"d4) Publisher/Original Copies: Department Fiscal, Department, Receiving AOTRM ALASKA JournaLfCommerce Alaska Oil & Gas Conservation Commission Public Notices FILE NO: AO-02-3-14-019 AO-02-3-14-019 Ad#: 10168142 RECEIVED JUL 2 4 2014 AOGCC AFFIDAVIT OF PUBLICATION I UNITED STATES OF AMERICA, STATE OF ALASKA, THIRD DISTRICT BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED Tracy Allison WHO, BEING FIRST DULY SWORN, ACCORDING TO THE LAW, SAYS THAT HE IS THE Business Manager OF THE ALASKA JOURNAL OF COMMERCE PUBLISHED AT 301 ARTIC SLOPE AVENUE, SUITE 350, IN SAID THIRD DISTRICT AND STATE OF ALASKA AND THAT ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WHICH WAS PUBLISHED IN SAID PUBLICATION 10/07/2012 7th DAY OF OCTOBER 2012 AND THERE AFTER FOR 1 CONSECUTIVE WEEK(S) AND THE LAST PUBLICATION APPEARING ON 10/07/2012 Tracy Allison Business Manager SUBSCRIBED AND SWORN BEFORE ME THIS 8th DAY OF October 2012 NOTARY PUBLIC "l' 'l . U t MY Notary Public (p f c1/�� BELINDA CUMMINGS State of Alaska My Commission Expires Jun 14, 2016 ATTACH PROOF OF PUBLICATION HERE Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re: Pt. McIntyre Oil Pool, Pt. McIntyre Oil Field Niakuk Oil Pool, Prudhoe Bay Field West Beach Oil Pool, Prudhoe Bay Field Proposed Amendment of Pool Rules and Area Injection Order BP Exploration (Alaska) Inc., by appli- cation dated September 19, 2012, has requested that Conservation Orders Number 317B (C0317B), 311B (C0311 B), and 329.05 (Corrected) (C0329), which establish pool rules governing development of the Pt. McIntyre Oil Pool, Pt McIntyre Oil Field, and the Niakuk Oil Pool and West Beach Oil Pool, Prudhoe Bay Field respectively and Area Injection Order No. 4E (A104E) be amended to expand the Affected Area of C0317B and A104E and contract the Affected Area of C0311 B and C0329. The AOGCC has tentatively scheduled a public hearing on this application for November 13, 2012 at 9:00 a.m. at the Alaska Oil and Gas Conserva- tion Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on October 23, 2012. If a request for a hearing is not timely filed, the AOGCC may consider the is- suance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 793-1221 after October 26, 2012. In addition, written comments regard- ing this application may be submitted to the Alaska Oil and Gas Conserva- tion Commission, at 333 West 7th Avenue, Suite 100, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on November 8, 2012, except that, if a hearing is held, comments must be received no later than the conclusion of the No- vember 13, 2012 hearing. If, because of a disability, special ac- commodations may be needed to comment or attend the hearing, con- tact the AOGCC's Special Assistant, Jody Colombie, at 793-1221, no later than November 9, 2012. By:/s/Cathy P. Foerster Chair, Commissioner Pub:10/7/2012 Ad#10168142 STATE OF ALASKA I NOTICE TO PUBLISHER ADVERTISING ORDER NO. ADVERTISING INVOICE MUST BE IN TRIPLICATE SHOWING ADVERTISING ORDER NO., CERTIFIED O-OZ-S-1 A_019 AFFIDAVIT OF PUBLICATION (PART 2 OF THIS FORM) WITH ATTACHED COPY OF �F ORDER ADVERTISEMENT MUST BE SUBMITTED WITH INVOICE BOTTOM FOR INVOICE ADDRESS F AOGCC AGENCY CONTACT I DATE OF A.O. R 333 West 711 Avenue. Suite 100 o Ancherage. AK 99501 M T 0 Alaska Journal of Commerce 301 Arctic Slope Avenue, Suite 350 Anchorage AK 99518 United states of America State of division. PHONE lPCN 7 7 - 1 LL. 1 ADVERTISEMENT REQUIRED: ASAP THE MATERIAL BETWEEN THE DOUBLE LINES MUST BE PRINTED IN ITS ENTIRETY ON THE DATES SHOWN. SPECIAL INSTRUCTIONS: AFFIDAVIT OF PUBLICATION REMINDER ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. Before me, the undersigned, a notary public this day personally appeared ATTACH PROOF OF PUBLICATION HERE. who, being first duly sworn, according to law, says that he/she is the of Published at in said division and state of and that the advertisement, of which the annexed is a true copy, was published in said publication on the day of 2012, and thereafter for consecutive days, the last publication appearing on the day of , 2012, and that the rate charged thereon is not in excess of the rate charged private individuals. Subscribed and sworn to before me This _ day of 2012, Notary public for state of My commission expires _ Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: To: Friday, September 28, 2012 2:16 PM Singh, Angela K (DOA); Ballantine, Tab A (LAW); Brooks, Phoebe L (DOA); Colombie, Jody J (DOA); Crisp, John H (DOA); Davies, Stephen F (DOA); Ferguson, Victoria L (DOA); Fisher, Samantha J (DOA); Foerster, Catherine P (DOA); Grimaldi, Louis R (DOA); Johnson, Elaine M (DOA); Jones, Jeffery B (DOA); Laasch, Linda K (DOA); Bender, Makana K (DOA); McIver, Bren (DOA); McMains, Stephen E (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Norman, John K (DOA); Okland, Howard D (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); Wallace, Chris D (DOA); Aaron Gluzman; Aaron Sorrell; Bruce Williams; Bruno, Jeff J (DNR); caunderwood@marathonoil.com; Casey Sullivan; Dale Hoffman; David Lenig; Donna Vukich; Eric Lidji; Erik Opstad; Franger, James M (DNR); Gary Orr; Smith, Graham 0 (PCO); Greg Mattson; Heusser, Heather A (DNR); Jason Bergerson; Jennifer Starck; jill. a.mcleod@conocophillips. com; Joe Longo; King, Kathleen J (DNR); Lara Coates; Lois Epstein; Marc Kuck; Steele, Marie C (DNR); Matt Gill; Maurizio Grandi; OilGas, Division (DNR sponsored); Bettis, Patricia K (DNR); Perrin, Don J (DNR); Peter Contreras; Pexton, Scott R (DNR); Richard Garrard; Ryan Daniel; Sandra Lemke; Talib Syed; Wayne Wooster; Woolf, Wendy C (DNR); William Hutto; William Van Dyke; (michael.j.nelson@conocophillips.com); (Von. L. Hutchins@conocophillips.com); AKDCWelllntegrityCoordinator; alaska@petrocaic.com; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Penrose; Bill Walker; Bowen Roberts; Bruce Webb; Claire Caldes; Cliff Posey; Crandall, Krissell; D Lawrence; dapa; Daryl J. Kleppin; Dave Harbour; Dave Matthews; David Boelens; David Duffy; David House; Scott, David (LAA); David Steingreaber; Davide Simeone; ddonkel@cfl.rr.com; Dennis Steffy; Elowe, Kristin; Erika Denman; Francis S. Sommer; Gary Laughlin; Schultz, gary (DNR sponsored); ghammons; Gordon Pospisil; Gorney, David L.; Greg Duggin; Gregg Nady; Gregory Geddes; gspfoff; Jdarlington (jarlington@gmail. com); Jeanne McPherren; jeff.jones@alaskajournal.com; Jones, Jeffery B (DOA); Jerry McCutcheon; Jill Womack; Jim White; Jim Winegarner; Joe Lastufka; news@radiokenai.com; Easton, John R (DNR); John Garing; John S. Haworth; John Spain; Jon Goltz; Jones, Jeffrey L (GOV); Judy Stanek; Houle, Julie (DNR); Julie Little; Kari Moriarty; Kaynell Zeman; Keith Wiles; Kelly Sperback; Gregersen, Laura S (DNR); Luke Keller; Marc Kovak; Mark Dalton; Mark Hanley (mark.hanley@anadarko.com); Mark P. Worcester; Kremer, Marguerite C (DNR); Michael Jacobs; Mike Bill; mike@kbbi.org; Mike Morgan; Mikel Schultz; Mindy Lewis; MJ Loveland; mjnelson; mkm7200; knelson@petroleumnews.com; Nick W. Glover; NSK Problem Well Supv; Patty Alfaro; Decker, Paul L (DNR); Paul Figel; Paul Mazzolini; Randall Kanady; Randy L. Skillern; Delbridge, Rena E (LAA); Renan Yanish; Robert Brelsford; Robert Campbell; Ryan Tunseth; Scott Cranswick; Scott Griffith; Seth Holtshouser; Shannon Donnelly; Sharmaine Copeland; Shellenbaum, Diane P (DNR); Slemons, Jonne D (DNR); Sondra Stewman; Stephanie Klemmer; Moothart, Steve R (DNR); Steven R. Rossberg; Suzanne Gibson; sheffield@aoga.org; Taylor, Cammy 0 (DNR); Davidson, Temple (DNR); Teresa Imm; Terrie Hubble; Thor Cutler; Tim Mayers; Tina Grovier; Todd Durkee; Tony Hopfinger; trmjrl; Vicki Irwin; Walter Featherly; Williamson, Mary J (DNR); yjrosen@ak.net Subject: Public Notice (PtMc Expansion) Attachments: PtMcExpansion.pdf Jody J. Colombie Special Assistant Alaska Oil and Gas Conservation Commission 333 Guest 7th Avenue Anchorage, AK 9.9501 (907)793-1221 (phone) (907)276-7542 (fax) Easy Peel® Labels It ^ Bend along line to 11 Use Avery@ Template 51600 11 Feed Paper expose Pop-up EdgeTh' Mary Jones David McCaleb XTO Energy, Inc. IHS Energy Group Cartography GEPS 810 Houston St., Ste. 200 5333 Westheimer, Ste.100 Ft. Worth, TX 76102-6298 Houston, TX 77056 Jerry Hodgden Richard Neahring Hodgden Oil Company NRG Associates 408181h St. President Golden, CO 80401-2433 P.O. Box 1655 Colorado Springs, CO 80901 Bernie Karl CIRI K&K Recycling Inc. Land Department P.O. Box 58055 P.O. Box 93330 Fairbanks, AK 99711 Anchorage, AK 99503 North Slope Borough Richard Wagner Planning Department P.O. Box 60868 P.O. Box 69 Fairbanks, AK 99706 Barrow, AK 99723 Jack Hakkila Darwin Waldsmith P.O. Box 190083 P.O. Box 39309 Anchorage, AK 99519 Ninilchik, AK 99639 Penny Vadia 399 W. Riverview Ave. Soldotna, AK 99669-7714 AXMRY@ 5960 rm i George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Mark Wedman Halliburton 6900 Arctic Blvd. Anchorage, AK 99502 Baker Oil Tools 795 E. 94th Ct. Anchorage, AK 99515-4295 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 James Gibbs P.O. Box 1597 Soidotna, AK 99669 Etiquettes faciles & peter A Repiiez a la hachure afro de iPflC rip www.averycom #1 ZE RECEIVED SEP 25 2012 AOGCC September 19, 2012 Cathy Foerster Chairman Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alf 99501 BP Exploration (Alaska) Inc 900 East Benson Boulevard P0. Box 196612 Anchorage, Alaska 99519-6612 Main 907 5645111 RE: Expansion and Contraction of Point McIntyre, Niakuk and West Beach Affected Pool and AIO Areas (Conservation Orders 317B, 311 B, & 329.05 and Area Injection Order 4E) Dear Cathy Foerster: BP Exploration (Alaska), Inc. (BPXA), operator of the Prudhoe Bay Unit (PBU), on behalf of itself and Working Interest Owners, requests modification of Conservation Orders (CO) 317B, 311 B, and 329.05corrected and Area Injection Order (AIO) 4E. These amendments are necessary because BPXA, acting in its capacity as Unit Operator, applied to the Department of Natural Resources and received approval for enlargement of the Pt. McIntyre Participating Area ("PMPA") and contraction of the West Beach Participating Area ("WBPA"). Accordingly, BPXA hereby petitions the Commission to amend the above referenced rules as necessary to accommodate expansion and contraction of the associated pool and AIO affected areas. The proposed expansion of the Point McIntyre Pool (PMP) is based on new well information and new seismic interpretation that extends the field limits based on the area capable of contributing to production. The proposed expansion includes two areas, referred to in the supporting documentation as North Expansion Area and Southeast Expansion Area. The two expansion areas are depicted and described in Attachment 1. a] The following attachments are provided in support of this application for the expansion and the simultaneous contraction of the Pool and AIO affected areas. Attachment 1: Pool, and AIO boundaries with Expansion and Contraction Areas. Attachment 2 Text & Figures: Proposed Pool and AIO. Information in support of these amendments is attached. Please maintain as confidential those certain attachments attached and labeled "CONFIDENTIAL" in accord with 20 AAC 25.537(b). Should you have questions regarding this application or should you require additional information to aid in your review please do not hesitate to contact Chantal Walsh at (907) 564-4162 Thank you for your timely consideration of this request. Sincerely, ),I ,,, K If ;- -' Katrina Cooper Manager Base Management Enclosures CC: Mark Agnew (ExxonMobil) Glean Frederick (Chevron) Jeff Spatz (BPXA) David Lenig (BPXA) Cathy Foerster (AOGCC) Kay Triplett (ExxonMobil) Judy Buono (BPXA) Bob Gerik (BPXA) Steve Krohn (ExxonMobil) Gary Benson (BPXA) Chantal Walsh (BPXA) Bruce Laughlin k'BPXA) Katrina Cooper (BPXA) Patricia Bettis (DO&G) Jon Schultz (CPAI) RL Skillern (BPXA) Eko Apolianto (BPXA) Application for Expansion and Contraction of Pt McIntyre, Niakuk, and West Beach Pool and AIO Areas September 19, 2012 Attachment 1 The leases or portion of leases contemplated for inclusion in the Point McIntyre Pool and Area Injection order (AIO) 4E and for exclusion from the West Beach Pool and Niakuk Pool are depicted in Section I: Location Map for the Pool and NO Expansion and Contraction Areas and are listed in Section II: Legal Description of the Pool and NO Expansion and Contraction Areas. All lessees and owners of the subject leases are Working Interest Owners of the Prudhoe Bay Unit. The map in section I below summarizes all requested changes to the Oil Pools and NO in one image. A clearer step by step breakout of the various requested changes; can be found on attachments 1 A,1 B,1 C and 1 D for the oil pool changes and on attachments 1 E, and 1 F for the NO changes. Section I: Location Map for the Pool and AIO Expansion and Contraction Areas Location Mao v ■ 2 ■ 33 ■ Is, INN Proposed Areas of 1 T12 i Expansion for the Point McIntyre Oil j B Pool Rules l;e to -- p Proposed Proposed Area of Point McIntyre Oil Pool I expansion of Area . Contraction for l Injection Order4E e s Niakuk Oil Pool �{ Rules West Beach Oil Pool 115 ■ ■f Niakuk Oil Pool � 8 7 ■ ■ Prudhoe Bay Unit Boundary -Q�■ x'T ■ 15 4 625 Prudhoe Bay Lease Boundary _ AIO Expansions ` ool Expansions /30:... +rr r rr ✓ .__29 _..._—._.—., of Pool Contractions30 i.rrrr 02B299 02B300 028305 034628 03 Contractionpsearea jB,. the West Beach NOT Oil Pool Rules x i m.ce.my.0 aaw<tr.e xom.,m� ilso.-us.— x. m. a<i.d ouc su<ew zen < p.om. T12N x. memre. ms ". os mam<a . norcncs po bscm au pu w„eu. 5 dFmw fit T11N I Tt1N ' narvelma 6 hp.ren Ey BPx C.nog'.CMB EWv .l.<4 - ` a �. _ 1 Application for Expansion and Contraction of Pt McIntyre, Niakuk, and West Beach Pool and AIO Areas September 19, 2012 Section II: Legal Description of the Pool and AIO Expansion and Contraction Areas Point McIntyre Pool Expansion Areas Pt. McIntyre Pool North Expansion T. 13 N., R. 14E., Umiat Meridian, Alaska ADL 389945, Tract 120, Section 26: S'/2, 320 acres, Section 35: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548, 608.75 acres ADL 389946, Tract 121, Section 27: S'/z, NW'/4 Protracted, All Tide and Submerged Lands Shoreward of the Line Fixed by Coordinates Found in Exhibit A of the Final Decree, U.S. v. Alaska, No. 84 Original, 460.94 acres Section 28: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL312809, 395.06 acres Section 33: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL312809 and ADL365548, 378.52 acres Section 34: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548, 624.20 acres Pt. McIntvre Pool Southeast Expansion T. 12 N., R. 15E., Umiat Meridian, Alaska ADL 034626, Tract 5, Section 16: SW'/4, 160 acres, Section 21: NWi/4, N'/2 SWl/4, 240 acres ADL 034627, Tract 6, Section 17: S'/2, 320 acres, Section 20: N'/2, N'/2 S'/2, 480 acres Area Injection Order 4E Expansion Areas AIO 4E Expansion — Area 1 T. 13 N., R. 14E., Umiat Meridian, Alaska ADL 389945, Tract 120, Section 26: S'/2, 320 acres, Section 35: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548, 608.75 acres ADL 389946, Tract 121, Section 27: S'/2, NW'/4 Protracted, All Tide and Submerged Lands Shoreward of the Line Fixed by Coordinates Found in Exhibit A of the Final Decree, U.S. v. Alaska, No. 84 Original, 460.94 acres PA Application for Expansion and Contraction of Pt McIntyre, Niakuk, and West Beach Pool and AIO Areas September 19, 2012 Section 28: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL312809, 395.06 acres Section 33: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL312809 and ADL365548, 378.52 acres Section 34: Protracted, All Tide and Submerged Lands, Excluding State Oil and Gas Lease ADL365548, 624.20 acres A10 4E Expansion — Area 2 T. 12 N., R. 15E., Umiat Meridian, Alaska ADL 034626, Tract 5, Section 16: SW'/a, 160 acres, ADL 034627, Tract 6, Section 17: S'/2, 320 acres, West Beach and Niakuk Pool Contraction Areas West Beach Pool Contraction T. 12 N., R. 15E., Umiat Meridian, Alaska ADL 034626, Tract 5, Section 21: N'/2 SW'/4, 80 acres ADL 034627, Tract 6, Section 20: N'/2 S'/2, 160 acres Niakuk Pool Contraction T. 12 N., R. 15E., Umiat Meridian, Alaska ADL 034626, Tract 5, Section 16: SW'/4, 160 acres, Section 21: NW'/4, 160 acres i� J o. _J C) Y Z 0 'TQ W m N W W Q Z L Z a F- Z w Z a m W D cr EL o y �.r�g H� U LL Z O U Z O J d J Y Q Z 0 w CD a. cr a z Q m w i Er a r Z D Q m W 0 0 D CL CC b�b g b $ J N $ Y IL ��. w 11" d z cc w 0 cc 0 z 0 zz CC z w cc cr D 0 FL z D Q co w 0 m 0 D cc a- hW ol all fill LX Application for Expansion and Contraction of Pt McIntyre, Niakuk, and West Beach Oil Pool and A10 Areas Attachment 2: Text Proposed Pt. McIntyre, Niakuk,and West Beach Pool and AIO Summary The proposed expansion of the Point McIntyre Oil Pool is based on new well information and new seismic interpretation that extends the field limits based on the area capable of contributing to production. The calculated OOIP increased the original 1994 estimate of 777 mmbo to the current estimate of 913 mmbo. The proposed expansion areas account for 38 mmbo of this increase, and the remaining (98 mmbo) is due to improved understanding of OOIP within the original oil pool boundaries. Figure 1 shows the two proposed expansion areas, referred to as the North Expansion Area and the Southeast expansion area Definition of the Oil Pool Limits The proposed oil pool limits are based on a combination of structural mapping and well information that define the estimated limits of oil production. Figure 2 shows the gross oil column thickness within the Kuparuk Formation (i.e. Top Kuparuk to the oil water contact). The northern and eastern limits of the field are defined where the Top Kuparuk intersects the field -wide owc of -9069 TVDss. Current well control suggests the reservoir should be productive to the structural limits of the field in these areas. The southern limit of the field is defined by the major trapping faults. The western limit of the field is defined by the extent of reservoir quality sand as the reservoir degrades to the west. There is no new information to suggest the western oil pool boundary should be changed from the current location. The P2-22A well was drilled into the North Expansion Area and has established oil production beginning in May 2010 (Figure 3). The location of the Pt. McIntyre field limit in the Southeast Expansion Area is shown. in Figure 4. The 2008 P2-456 well established oil production at the eastern limit of the current oil pool (Figure 5). High fluid rates with oil production support the existence of good quality within structural closure up to the oil pool limit. The Top Kuparuk structure does not dip below the -9069 owc anywhere in the Southeast Expansion Area, indicating there is no apparent structural closure to the east. In addition, there is continuous Kuparuk interval present from the Pt. McIntyre Field to the West Beach Field, so there is no separation of the two fields by reservoir "pinch -out" identified from 3D seismic data. The West Beach Field has a much deeper owc (-9240) than the Pt. McIntyre Field (-9069), suggesting a stratigraphic separation of the two fields as the most plausible explanation. The Gull Island 1 and Gull Island 3 wells to the east have no reservoir quality sands above the -9240 (West Beach owc) indicating that the closure to the east is due Confidential under AS 38.05.035 Confidential under 20 ACC 25.537(b) And any other applicable law. Application for Expansion and Contraction of Pt McIntyre, Niakuk, and West Beach Oil Pool and AIO Areas to reservoir degradation in the Upper Kuparuk interval which tends to support stratigraphic separation of West Beach and Pt. McIntyre Fields. Figure 6 is a schematic structural cross-section showing the concept of stratigraphic closure of the Pt. McIntyre Field to the east. The extent of reservoir quality sand to the east is uncertain, but it degrades to a non -reservoir facies in the Gull Island 1 area. The lack of additional wells between P2-45B and Gull Island 1 make the specific determination of the field limit uncertain. In contrast, there is dense well control in the West Beach Field (Figures 7 and 8). The eastern extent of the West Beach Field is between WB-06 and Gull Island 3 and the northern extent is between WB-06 and Gull Island 1. The cross -sections on Figures 6 & 7 show that the Kuparuk is a non -reservoir facies above the Niakuk Field OWC indicating the pool does not extend as far west as originally defined. It is possible that the current Niakuk pool may extend over the eastern portion of the Pt McIntyre pool. The Niakuk pool needs to be contracted in this area to avoid overlapping the Niakuk pool with the Pt. McIntyre pool. Figure 9 shows the estimated extent of the Pt. McIntyre Field in the proposed Southeast Expansion Area. Figure 8 shows the maximum possible extent of the West Beach Field and the proposed contraction area of the West Beach Oil Pool. Confidential under AS 38.05.035 2 Confidential under 20 ACC 25.537(b) And any other applicable law. W L L.L N W E U C6 7% O N M m 2 /!4 O i Q c d Q � U C� N _ I M O `' c4 O U d = Y d N O a) O o m �w� n Uzi o - — N i O U ■i 1 � O C R � O Ana a-0. 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