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Home My WebLink AboutO 193Other Order 193 Docket Number: OTH-22-005 1. ------------------- Background emails. 2. February 9, 2022 Notice of public hearing, affidavit, email and bulk mail distribution. 3. March 29, 2022 Hearing transcript, DNR question. 4. -------------------- Yearly summaries of Dillion platform well plug and abandonment. 5. December 5, 2023 Hilcorp letter regarding changes in planned Plug and Abandonment activities 6. August 22, 2024 Hilcorp 2024 Cook Inlet Well P&A plan updates 7. November 15, 2024 Hilcorp 2024 Cook Inlet Well P&A Report 8. November 14, 2025 Hilcorp 2025 Cook Inlet Well P&A Report 9. March 21, 2025 MGS Oil Pool Abandonment and Plugging - AOGCC clarification and expectations 10. August 21, 2025 Hilcorp proposed update of O 193 (O 193.001) 11. August 26, 2025 background and clarification/expectations emails (Confidential items held in secure storage) STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: Hilcorp’s request to reprioritize the plugging and abandonment plans for wells on the Baker, Dillon, and Spurr platforms in the Cook Inlet Offshore. ) ) ) ) ) ) ) Docket Number: OTH-22-005 Other Order 193 Hilcorp Alaska, LLC Cook Inlet Offshore platform well P&As May 19, 2022 DECISION AND ORDER By email dated December 30, 2021, Hilcorp Alaska, LLC (Hilcorp) requested approval from the Alaska Oil and Gas Conservation Commission (AOGCC) to delay the plugging and abandonment (P&A) of offshore wells on the Spurr platform in Cook Inlet (CI) and proposed to P&A wells on the Dillon and Baker platforms which Hilcorp considered to be higher priority. On January 6, 2022, the AOGCC asked forinformation to support Hilcorp’s request. Hilcorp provided supporting information on January 11, 2022. Because the P&A of all wells on three platforms in CI is a matter of public interest, on its own motion, AOGCC set a public hearing to discuss Hilcorp’s P&A plans for wells on the Baker, Dillon, and Spurr platforms. Pursuant to 20 AAC 25.540, the AOGCC scheduled a public hearing on March 29, 2022. On February 10, 2022, the AOGCC published notice of that hearing on the State of Alaska’s Online Public Notice website and the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list and mailed copies of the notice to all persons on the AOGCC’s mailing distribution list. On February 13, 2022 the notice was published in the Anchorage Daily News. On March 29, 2022, the AOGCC held the hearing. FINDINGS: 1. Hilcorp performed an assessment of the long-term shut in wells on the Dillon, Baker and Spurr platforms in CI that included subsurface and surface risk factors. Based on the assessment, Hilcorp proposes to P&A wells on the Dillon, Baker and Spurr platforms in 2022, 2023 and 2024, respectively. 2. Dillon platform is considered to have the highest subsurface risk, and thus be the highest priority candidate for P&A operations, since most of its wells do not have any downhole cement plugs. In contrast, the wells on the Spurr platform are lower priority since all have at least one cement plug between the reservoir and the surface. 3. Hilcorp performed a structural assessment of the platforms in November 2021, including the condition of leg and tidal zone, jacket stresses, cathodic protection, power supply and pipelines. Based on this assessment, Dillon platform is considered to be the highest priority for well abandonment followed by Baker platform and then Spurr platform. Other Order 193 May 19, 2022 Page 2 of 3 4. Production and injection operations ceased on the Dillon, Baker and Spurr platforms in 2002, 2014 1, and 1992, respectively. 5. In 2009, based on information provided by the operator, AOGCC determined that the wells on the Spurr platform had no further utility. Marathon, the operator at the time, planned to P&A the wells by 2013. Before the wells were P&A’d, the asset was purchased by Hilcorp which requested an extension to re-evaluate the platform for potential startup. In 2017, Hilcorp’s applications for well suspension renewals were denied by the AOGCC for a lack of future utility. The AOGCC approved limited well suspension sundries on the conditions that a timeline was set for well P&As and Hilcorp submit a yearly progress report. Hilcorp has taken four years to get the Spurr platform in a condition to support the well P&A campaign. Well P&As on the Spurr platform were planned to start in 2021 but were delayed again due to crane malfunction. 6. Suspension sundries for wells on the Spurr platform expired on December 31, 2021. 7. Hilcorp states that the cranes and helidecks on the Dillon and Baker platforms are operational and do not need additional integrity inspections. 8. Well 05RD3 on the Spurr platform does not have a tree or pressure monitoring equipment. 9. Potential undeveloped hydrocarbon resources near the Dillon, Baker and Spurr platforms could be accessed and drilled from the open well slots on other nearby platforms. CONCLUSIONS: 1. The P&A of wells with no future utility is required per 20 AAC 25.105. 2. P&A operations on wells on Dillon, Baker and Spurr platforms are appropriately ordered in accordance with the ranking of surface and subsurface risks. 3. Due to delays in the P&A of wells on the Spurr platform, it is appropriate to set dates by which wells on Dillon, Baker and Spurr platforms will be P&A’d. 4. Suspension sundries for wells on the Spurr platform expired on December 31, 2021 and will not be renewed because the wells have no future utility. 5. P&A of the existing wells on Dillon, Baker and Spurr platforms still allows for development of future hydrocarbon resources via the open well slots on the nearby platforms. NOW THEREFORE IT IS ORDERED: Hilcorp’s request to reprioritize the P&A plans for wells on the Baker, Dillon, and Spurr platforms in the Cook Inlet Offshore is GRANTED per the following conditions: 1. Wells on the Dillon, Baker and Spurr platforms will be P&A’d in 2022, 2023 and 2024, respectively. 1 2014 is when all production from the Baker platform ceased, oil production ceased in 2003. Other Order 193 May 19, 2022 Page 3 of 3 2. Well P&A activity will begin at Dillon platform immediately and is to be completed by the end of the ice-free season. If for some reason P&A activity cannot begin on Dillon platform, then P&A activity at Baker will take place according to this timeline. 3. Spurr 05RD3 must have a tree and pressure monitoring equipment installed not later than June 15, 2022. 4. Pressure monitoring checks are required on all Spurr wellheads on a monthly basis until the wells at Spurr are P&A’d. AOGCC is to be given an opportunity to witness the monthly platform checks. Results of the monthly checks to be sent to the AOGCC in an Excel table. 5. No later than November 15 th of each year, Hilcorp shall provide a report to the AOGCC on the P&A activities that were completed during the previous summer and the plans for the next year’s open water season. The report shall include, but not be limited to, the following information: a. A well-by-well discussion of how the P&A of each well went and how this compared to what was anticipated; b. A discussion of challenges and lessons learned during the P&A operations; c. A discussion of how these lessons learned will be applied to the future P&A programs; and d. A discussion on whether or not the P&A scheduled ordered in 1 above needs to be adjusted and why. e. An update on the maintenance, functionality and integrity of equipment on the Spurr platform to ensure that it will be in a condition to P&A wells in 2024. 6. Hilcorp shall meet with the AOGCC no later than December 1 st each year to discuss the report required in 5 above. DONE at Anchorage, Alaska and dated May 19, 2022. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, 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 recon- sideration 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. Dan Seamount Digitally signed by Dan Seamount Date: 2022.05.19 10:28:54 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.05.19 11:41:29 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.05.19 12:46:26 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:Other Order 193, Hilcorp, Cook Inlet Offshore Date:Thursday, May 19, 2022 2:17:00 PM Attachments:other193.pdf Hilcorp’s request to reprioritize the plugging and abandonment plans for wells on the Baker, Dillon, and Spurr platforms in the Cook Inlet Offshore. Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 From:Carlisle, Samantha J (OGC) To:Aras Worthington; Dan Marlowe (dmarlowe@hilcorp.com); "chelgeson@hilcorp.com"; Josh Allely - (C); Vanessa Hughes Cc:McLellan, Bryan J (OGC) Subject:FW: Other Order 193, Hilcorp, Cook Inlet Offshore Date:Thursday, May 19, 2022 2:19:00 PM Attachments:other193.pdf Please see attached. From: Carlisle, Samantha J (OGC) Sent: Thursday, May 19, 2022 2:17 PM To: AOGCC_Public_Notices <AOGCC_Public_Notices@list.state.ak.us> Subject: Other Order 193, Hilcorp, Cook Inlet Offshore Hilcorp’s request to reprioritize the plugging and abandonment plans for wells on the Baker, Dillon, and Spurr platforms in the Cook Inlet Offshore. Samantha Carlisle AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Mailed 5/19/22 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL OTHER ORDER 193.001 Mrs. Trudi Hallet CIO Asset Team Lead 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 Re: Docket Number: OTH-25-015 Request for Administrative Approval to Other Order 193 Cook Inlet Offshore Platform Well P&As Dear Mrs. Hallet: By electronic mail dated August 21, 2025, Hilcorp Alaska, LLC (Hilcorp) requested the Alaska Oil and Gas Conservation Commission (AOGCC) update Other Order 193 (OO 193) to reflect the current and planned future P&A activity and to adjust the schedule according to a revised risk- ranking of wells on Hilcorp’s idle Cook Inlet platforms. Specifically, Hilcorp requested the following: To formally update OO-193 to reflect current plans, Hilcorp requests that Conditions # 1 and #2 of OO 193 are modified to read: 1. Well P&As on the MGS C platform will begin in 2026 and are expected to take two seasons to complete. P&A on the Spurr platform is targeted to begin after completion of the MGS C platform. Finally, the remaining wells on the Baker platform will either be developed or be P&A’d following the MGS C and Spurr platform P&A work. 2. Completed Findings: The following P&A activity and correspondence has occurred since the May 19, 2022, issuance of OO 193, based on the annual reports (condition 5 of OO 193) and the referenced correspondence: x 2022: Dillon Platform was prepared for P&A activity and a temporary camp installed. Well diagnostic work was completed on all wells, and roughly more than half of the P&A work was completed. Hilcorp committed to completing the Dillon P&As and beginning P&A activity on Baker platform in 2023. AOGCC agreed to the proposal, recognizing that it would delay the P&A of Spurr Platform wells by 1 year. Other Order 193.001 January 6, 2026 Page 2 of 4 x 2023: The remaining 9 wells on Dillon Platform were P&A’d after a 6-week campaign ending June 26, 2023. The Baker platform was then prepared for P&A activity, including moving the temporary camp from Dillon to Baker and rebuilding the helideck. o September 2023, MGS-C became an idle platform after a subsea pipeline failure, with no potential to restore oil or gas production economically. o December 5, 2023, Hilcorp sent a letter to AOGCC titled “2023 Cook Inlet P&A Plan Updates”, in which Hilcorp informed the AOGCC of its desire to plug only the existing MGS Oil Pools, leaving the shallower MGS Gas pool available for potential perforating or rig sidetrack to test the gas potential under the platform. o Hilcorp also informed AOGCC in the same letter of its desire to P&A the MGS-C Platform wells after finishing plugging the MGS Oil Pools on Baker Platform, but before the Spurr platform wells were P&A’d. Hilcorp’s risk-based rational for reprioritization was consistent with the goals of OO 193. x 2024: Baker Platform well diagnostic work was completed, but only four wells were partially or completely P&A’d. Although Hilcorp submitted P&A sundry applications for most of the wells on Baker platform, these applications did not address the uncemented MGS gas zones nor did they P&A the MGS-oil zones to AOGCC’s satisfaction. Progress stalled and not much of the 2024 ice-free season was used for plugging activity. o August 22, 2024, Hilcorp sent a letter in response to an AOGCC request for information regarding the risk profile of the MGS-C platform and the reiterated its desire to plug the wells on MGS-C ahead of the Spurr Platform wells because the open perforations in wells at MGS-C were riskier than the plugged perforations in wells at Spurr Platform. The letter also discussed Hilcorp’s determination that repairing a subsea pipeline to recover the remaining resources from MGS-C platform was not profitable. x 2025: Baker platform sundry applications were approved for all but 3 wells on Baker platform and the oil pools were plugged. The MGS gas pool has not been plugged per AOGCC regulations in any of the Baker wells, nor have the surface plugs been placed. The wells are in a suspended status, with the exception of two disposal wells and one well that penetrated the West Foreland formation below the MGS oil pools. o February 13, 2025, Hilcorp sent an email with Spurr platform inspection reports from a 3rd party engineering firm indicating that the platform is in good overall condition and has an inspection program developed using guidance from API RP 2SIM. o AOGCC notified Hilcorp via email dated March 21, 2025, informing them of AOGCC’s expectation for isolating the various MGS oil pools during the P&A campaign. Conclusions: 1. The wells at MGS C-platform have more risk of oil spills or gas leaks than the wells at Spurr platform because most of the perforations in MGS-C wells are not plugged with cement. Other Order 193.001 January 6, 2026 Page 3 of 4 2. The Spurr platform is part of a regular inspection program, is structurally in good overall condition, and not at imminent risk of structural failure. 3. Delaying the P&A of Spurr platform wells and the remainder of the P&A work at Baker platform for two years will not significantly increase risk to the platforms or their wells. 4. Accelerating the P&A of MGS-C platform wells ahead of Spurr platform wells will reduce risk of loss of containment of oil and gas at MGS-C platform. 5. Plugging the wells on Dillon platform took two years to complete, significantly longer than anticipated when OO 193 was issued. 6. Plugging the MGS Oil Pool in all but 3 of the wells on Baker platform also took two years to complete. None of the wells have been plugged across the MGS Gas pool and still require surface plugs. Plugging Baker platform wells will take a minimum of 3 years to complete, significantly longer than anticipated when OO 193 was issued. 7. Hilcorp expects to take two years to complete plugging of the wells at MGS-C platform. 8. The purpose of OO 193 was to ensure Cook Inlet P&A activity continues at a measured and steady pace, prioritized according to well and platform risk, and to ensure P&A at Spurr platform is not delayed indefinitely. As discussed in the original order, all production ceased on Spurr platform in 1992. Wells had been in suspended status until the suspensions expired in 2021. The suspensions could not be renewed per AOGCC regulations because the wells have no future utility. AOGCC regulations require wells to be either completed as production or service wells, suspended or P&A’d. OO 193 allows for the wells on Spurr to be non-compliant until 2024 or until otherwise agreed by the AOGCC. This deadline for P&A of the wells at Spurr Platform should be adjusted to allow for the MGS-C platform wells to be P&A’d first. 9. Hilcorp’s request to P&A the wells at MGS-C platform ahead of the Spurr and Baker platform wells is in the best interest of the State of Alaska, however, conditions of approval are appropriate to ensure the Spurr platform wells are brought into compliance without additional delay. The AOGCC conditionally approves Hilcorp’s request to modify OO 193 as follows: 1. Condition #1: Wells on Dillon, Baker, MGS-C and Spurr platforms will be P&A’d as follows: a. Dillon in 2022-2023 (complete) b. Baker MGS Oil Pools in 2024-2025 (complete, excepting 3 wells which AOGCC has approved to be P&A’d when the MGS gas pool is P&A’d in the future) c. MGS-C in 2026-2027. Well inspections to be performed for all wells on Spurr platform during the ice-free season of 2026. AOGCC to be given opportunity to witness these inspections. Inspection reports to be submitted with a 10-404, must include all information required in a typical suspended well inspection report. These inspections will not establish suspension status for any of the wells. Other Order 193.001 January 6, 2026 Page 4 of 4 d. Spurr in 2028. If MGS-C platform P&A work is not completed in 2027, plugging of remaining MGS-C wells and Spurr wells will be done concurrently in 2028. Exceptions will be made where wells are shown to have future utility. e. Baker: P&A all remaining wells, including MGS Gas & Oil Pools and surface plugs in 2029. Exceptions will be made where wells are shown to have future utility. f. The AOGCC intends to impose daily civil penalties for each well at Spurr platform not P&A’d in compliance with AOGCC regulations beginning November 16, 2028. Daily penalties will be assessed beginning November 16, 2028, and must be paid monthly, starting on Dec 31, 2028 (for period Nov 16-Dec 31, 2028) and on the last day of every month thereafter until the wells are P&A’d according to AOGCC regulations. 2. Condition #2: Noted as complete. 3. All other conditions of approval in OO 193 still apply. DONE at Anchorage, Alaska and dated January 6, 2026. Jessie L. Chmielowski Gregory C. Wilson 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. Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2026.01.06 10:31:03 -09'00' Gregory C Wilson Digitally signed by Gregory C Wilson Date: 2026.01.06 14:45:39 -09'00' From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Other Order 193.001 (Hilcorp) Date:Tuesday, January 6, 2026 2:55:30 PM Attachments:OTHER193.001.pdf Docket Number: OTH-25-015 Request for Administrative Approval to Other Order 193 Cook Inlet Offshore Platform Well P&As Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v 11 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Daniel Taylor To:McLellan, Bryan J (OGC); Wyatt Rivard; AOGCC Reporting (CED sponsored); Coldiron, Samantha J (OGC); Rixse, Melvin G (OGC) Cc:Casey Morse; Trudi Hallett; Dan Marlowe Subject:RE: [EXTERNAL] RE: Hilcorp Request for Update of Other Order 193 - Cook Inlet Offshore P&As Date:Tuesday, August 26, 2025 1:39:12 PM Mr. McLellan, Considerable labor has been expended to prepare for well-work in 2026, though no single inspection was responsible. The East crane winches were removed in 2024 for a major overhaul completed in April 2025. The west crane is currently out of service for a major winch overhaul (scheduled to be finished by the end of 2025). The Helideck is continuously maintained. The camp is available and in decent condition, but it is currently winterized and will need to be reopened for support crews. The biggest efforts will be clearing the drill deck of the legacy drill rig and its support equipment. This will make room for the P&A package (see attached photos of MGS-C and Baker for comparison). Thank you, sir. Respecfully, Daniel Taylor, P.E. Well Integrity O: 907-777-8319 C: 907-947-8051 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, August 22, 2025 10:35 AM To: Wyatt Rivard <wrivard@hilcorp.com>; AOGCC Reporting (CED sponsored) <aogcc.reporting@alaska.gov>; Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Daniel Taylor <dtaylor@hilcorp.com>; Casey Morse <Casey.Morse@hilcorp.com>; Trudi Hallett <thallett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: [EXTERNAL] RE: Hilcorp Request for Update of Other Order 193 - Cook Inlet Offshore P&As Wyatt, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Has Hilcorp performed a platform inspection of MGS-C to understand what kind of repairs or prep work will be required to hit the ground running with wellwork in spring 2026? Is the crane functional? Helipad in good shape? Camp, etc? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Thursday, August 21, 2025 3:43 PM To: AOGCC Reporting (CED sponsored) <aogcc.reporting@alaska.gov>; Coldiron, Samantha J (OGC) <samantha.coldiron@alaska.gov>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Daniel Taylor <dtaylor@hilcorp.com>; Casey Morse <Casey.Morse@hilcorp.com>; Trudi Hallett <thallett@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com> Subject: Hilcorp Request for Update of Other Order 193 - Cook Inlet Offshore P&As Hello, Please find attached request to update Other Order 193 – Cook Inlet Offshore P&As. This request includes updates to P&A prioritization and includes current 2025 Baker Platform P&A scope and progress. Thank You, Wyatt Rivard | Well Integrity ManagerO: (907) 777-8547 | C: (509)670-8001 | RM:10616Hilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete From:McLellan, Bryan J (OGC) To:Dan Marlowe Cc:Wyatt Rivard; casey.morse@hilcorp.com Subject:MGS Oil Pool Abandonment and Plugging - AOGCC clarification and expectations Date:Friday, March 21, 2025 3:22:00 PM Dan, The intent of this email is to provide AOGCC’s expectations for plugging and abandonment of significant hydrocarbon zones within the Middle Ground Shoal (MGS) Oil Pool in accordance with 20 AAC 25.112. Background: Conservation Order 26 (August 4, 1966) Rule 3 designated 7 MGS Oil Pools which correlate as follows to Pan American Corporation State 17595 #4 well: MGS Oil Pool A – 5300-5830’ MGS Oil Pool B – 5830-6100’ MGS Oil Pool C – 6100-6400’ MGS Oil Pool D – 6400-6750’ MGS Oil Pool E – 6750-7050’ MGS Oil Pool F – 7050-7375’ MGS Oil Pool G – 7375-9215’ CO 26 Rule 4 allowed for Permissible Commingling in the same wellbore from: MGS Oil Pools B, C and D MGS Oil Pools E, F and G CO 31 (October 19, 1966) updated the Permissible Commingling list of Rule 4 to specify that Pool A must be segregated: MGS Oil Pool A MGS Oil Pools B, C and D MGS Oil Pools E, F and G CO 44 (July 19, 1967) changed the boundary between Pools A & B, but did not change the commingling permissions. MGS Oil Pool A – 5300-5720’ MGS Oil Pool B – 5720-6100’ CO 44A (January 12, 2017) Combined MGS Oil Pools A-G into a single oil pool AOGCC regulation 20 AAC 25.112(c) states that “Plugging of cased portions of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous strata and are prevented from migrating into other strata or to the surface.” A stringent interpretation of AOGCC’s regulation would require cement across every perforated stratum. The MGS Oil Pool, of almost 4,000’ in length per CO 44A, contains many perforated strata. However, the AOGCC will instead consider the plugging and isolation of the significant hydrocarbon bearing zones as meeting the intent of the regulation. For the purpose of plugging and abandoning the significant hydrocarbon bearing zones in the MGS Oil Pool, the AOGCC recognizes three separate strata aligning with CO 44 Rule 3’s Permissible Commingling Rule. These strata, depth referenced to Pan American Corporation State 17595 #4 well, are: 1. MGS Oil Pool A - 5300 – 5720’ MD 2. MGS Oil Pools B, C & D – 5720 – 6750’ MD 3. MGS Oil Pools E, F & G – 6750 – 9215’ MD. Each of these separate strata must be plugged separately in accordance with 20 AAC 25.112. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From:Wyatt Rivard To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] RE: OTH 193 Annual Report Review & MGS Oil P&A Pre-Hearing Discussion Date:Thursday, February 13, 2025 9:34:32 AM Attachments:1-30-2025 - Inspection Summary - Spurr (Confidential).pdf 1-10-2025 - Integrity Status - Spurr (Confidential).pdf Topside Spurr 2024.pdf Spurr Platform 2018 Topside Survey.pdf Hello Bryan, As discussed, there are six distinct surface and subsea inspection types used to monitor and maintain mechanical integrity on the Spurr platform. The attached 1-30-25 Inspection Summary table and 1-10-25 Integrity Status letter were generated by independent 3rd party engineers for inclusion with the 2025 Plan of Development to the DNR. The table and letter summarize the various inspection method results and include proposed inspection intervals going forward. This was the first year that this 3rd party summary was generated per a 2025 POD requirement. Separately, I’ve attached the 2024 Topside inspection survey. This is a primarily a visual inspection of framing, structure and surfaces for corrosion, weld damage, etc. This topside inspection is likely the most comparable to what AOGCC Inspectors would observe when visiting the platform. I’ve also attached the previous 2018 iopside survey. Per the inspection summary table, these topside inspections are on an annual frequency going forward. Thank You, Wyatt Rivard | Well Integrity ManagerO: (907) 777-8547 | C: (509)670-8001 | RM:10616Hilcorp Alaska, LLC | Anchorage, AK 99503 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, February 10, 2025 3:41 PM To: Wyatt Rivard <wrivard@hilcorp.com> Subject: [EXTERNAL] RE: OTH 193 Annual Report Review & MGS Oil P&A Pre-Hearing Discussion Wyatt, Let’s plan on Wed 2/19 9:00-10:30. Please send over the last 2 platform inspection reports form the Spurr platform so we have some time to review them before the meeting. Thank you CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Wyatt Rivard <wrivard@hilcorp.com> Sent: Thursday, February 6, 2025 3:36 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: OTH 193 Annual Report Review & MGS Oil P&A Pre-Hearing Discussion Hello Bryan, I was hoping to arrange a time for Hilcorp to come and formally meet per OTH-193 to discuss the 2024 Cook Inlet well P&A activity. Attendees would likely be myself, Dan Taylor (Well Integrity Engineer), Matt Petrowski (Geologist), Casey Morse (Operations Engineer) and Dan Marlowe (Operations Engineer) or Trudi Hallet (Asset Team leader). We’re planning to come ready to verbally review and discuss the updates as included in the 2024 Cook Inlet Well P&A Report (attached) as well as next steps for CIO P&A operations. Please let me know if any other deliverables are needed for this discussion. Once we have reviewed 2024 Cook Inlet P&A Activity, we’d also like to informally discuss the MGS Oil Pool reservoir abandonment as it relates to future Baker or MGS Platform P&A work. Looking at our internal calendars, any of the dates/times below would work well for our attendees but if there’s a different day or time that’s better for you please let me know. With the combined discussion topics, I thought would be good to have 90 minutes available for discussion. Potential Meeting Dates/Times Mon 2/17 @ 1-2:30 PM Wed 2/19 @ 9-10:30 or 1-2:30 PM Fri 2/21 Anytime 9AM-4 PM Thank You, Wyatt Rivard | Well Integrity ManagerO: (907) 777-8547 | C: (509)670-8001 | RM:10616Hilcorp Alaska, LLC | Anchorage, AK 99503 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. 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Platform: Spurr 2024 Topside Survey REPORT NO.:SPURR 24 Prepared by: Alex Forster Date: 09/24/2024 Rev: 00 Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 2 of 39 Table of Contents 1.Scope ............................................................................................................................................................... 3 2.Inspection Results Summary ............................................................................................................................. 3 3.Topside Inspection Data Sheets ........................................................................................................................ 5 3.1 Deck Beams- Drilling Deck………………………………………………………………………………………………………………………10 3.2 Deck Beams- Production Deck………………………………………………………………………………………..12 3.3 Skid Beams…………………………………………………………………………………………………………………………………..…………14 3.4 Trusses- Production Deck………………………………………………………………………………………………….…………………..16 3.5 Support Stanchions- Top Structure…..………………………………………………………….………………………………………..18 3.6 Helideck Structure- Top Deck…...……………………………………………………………………………..……………………………20 3.7 Brucker Davits……………………………………………………………………………………………………………………………….……...23 3.8 Crane foundation………………………………………………………………………………………………………………………..…………25 3.9 Flare Boom…………………………………………………………………………………………………………………………………………….27 3.10 General…………………………………………………………………………………………………………………………………….…………...29 Appendix A. Repair Program – Priority 1 ........................................................................................................39 Appendix B. Repair Program – Priority 2 ........................................................................................................39 Appendix C. Repair Program – Priority 3 ........................................................................................................39 Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 3 of 39 1.Scope The inspection covers above water structures, which includes the multiple decks and truss framing as well as framed structural supports for large equipment and deck appurtenances.Tanks, cranes (except crane foundations), rigs, piping, and production equipment, with the exception of their support structures, are not within the scope of the topside structural survey program. Production equipment and mechanical deck appurtenances fall under the scope of item-specific inspection programs and are therefore not covered under this inspection. Critical members and joints, which require a close detailed inspection, will be identified as they are observed. These areas, which by experience or evaluation are high stress locations or observed to be prone to material degradation, are thus essential to the integrity and function of topsides structures. Items that are critical to the integrity or function of the structure such as the platform seats, plate girders, and truss and frame members, are given higher priority of repair and have maintenance recommended at early signs of degradation. Additionally,the structure supporting safety equipment is also given a higher priority. Per the requirements of API RP 2D, crane inspections are performed separately from the overall topside inspection. To simplify and expedite the process, this report includes visual inspections of the south crane pedestal and connections. The crane boom, hoists, rope, and any other critical components of either crane are not in the scope of this evaluation. Note: Scope of fixed platforms inspections is summarized in the "Cook Inlet Platforms'Structural Integrity Program" which is updated yearly based on the results from all Level I, II,III/IV inspections. The program is based on the guidance from the API RP 2SIM. 2.Inspection Results Summary The Level I Spurr platform topside inspection was performed during the month of August 2024. The inspection was accomplished by performing a walk-through of the entire platform topside while conducting a visual assessment of the structural components. The condition of items were inspected for corrosion, deformation, wear, and unsafe load conditions. The inspection covered the deck beams and trusses, skid beams, walkways, Brucker davits, stairways, helideck, flare Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 4 of 39 boom, structural seats, and structural support framing for large equipment such as the cranes and the drill rig. Production equipment and mechanical deck appurtenances fall under the scope of item-specific inspection programs and were therefore not covered in this effort. Throughout the platform, various locations had limited access for visual inspection of the structure because of no personal access, piping,and/or equipment obstructing the view. The findings are then separated into three repair priority lists, which can be found in Appendix A, B, and C of this report. Priority 1 is given to items deemed to have or potentially have an impact on the topside structure load path or life safety if not repaired within one year. Priority 2 is given to items deemed to have or potentially have an impact on the topside structure load path or life safety if not repaired within the next 3-5 years.Priority 3 items are items that should be monitored for future degradation, but no other actions are required. This decision is made based on a number of factors including but not limited to corrosion levels, safety issues, deformation levels, location along the load path,and impact on the overall structural integrity. The major Level I inspection locations for the Spurr platform are as follows: 1. Deck Beams- Drilling Deck 2. Deck Beams- Production Deck 3. Skid Beams- Drilling Deck 4. Trusses- Production Deck 5. Structure Seats- Production Deck 6. Helideck Structure- Top Deck 7. Brucker Davits- Behind Galley- Lower-Level West 8. Crane Foundation- Top Deck 9. Flare Boom- Production Deck 10. General Walk Around Refer to Appendix A, B, and C for guidance on priorities and recommended repair timelines. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 5 of 39 Platform Spurr 2024 Inspection Results Summary Task 1-Deck Beams- Drilling DeckItem Observation Recommendations 1 General light-moderate corrosion noticed throughout deck beams for drilling deck Continue to monitor on an annual basis for worsening conditions 2 General coating failure throughout all deck beams for drilling deck Recoat areas of failed coating 3 Leaking roof in generator room and well rooms Fix all leaks in roof 4 Heavy corrosion in well rooms and generator room Clean and repair all holes in the roof 5 Not all areas inspected due to access, asbestos, and equipment in the way Get proper equipment and training to inspect in asbestos area Platform Spurr 2024 Inspection Results Summary Task 2-Deck Beams- production DeckItem Observation Recommendations 1 General light-moderate corrosion noticed throughout deck beams for drilling deck Continue to monitor on an annual basis for worsening conditions 2 Through wall corrosion on deck beams below Brucker, and heavy corrosion Repair areas of through wall corrosion 3 Inspect all areas that were not inspected Make a plan to inspect areas that are not accessible from walking around Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 6 of 39 Platform Spurr 2024 Inspection Results Summary Task 3-Skid BeamsItem Observation Recommendations 1 General light-moderate corrosion noticed in exposed areas and in the generator room Continue to monitor on an annual basis for worsening conditions 2 Water pooling in areas on the roof, which results in the skid beams sitting in standing water Get water to drain out of areas where it is pooling 3 Inspect all areas that were not inspected Make a plan to inspect areas that are not accessible from general walk around, this includes entering areas with asbestos Platform Spurr 2024 Inspection Results Summary Task 4-Trusses- Production DeckItem Observation Recommendations 1 Water pooling in areas where trusses and columns are intersecting with the floor Find a way to get the water to drain in these areas 2 Moderate- heavy corrosion at intersections of floor and on flanges of beams Repair all areas of moderate- heavy corrosion 3 Coating failure found throughout platform Recoat all areas of failed coating Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 7 of 39 Platform Spurr 2024 Inspection Results Summary Task 6-Helideck and Support StructureItem Observation Recommendations 1 Fencing beginning to come undone on its supports Retie fencing to its supports 2 Areas of moderate corrosion Clean and recoat all areas of moderate, or worse, corrosion 3 Standing water on roof of top deck, where support of stairs are sitting in Find a way to drain all standing water on the roof 4 Unable to inspect entire structure do to access Come up with a plan to inspect all aspects of the structure 5 General corrosion Continue to monitor annually for worsening conditions Platform Spurr 2024 Inspection Results Summary Task 5- Structure Seats- Top StructureItem Observation Recommendations 1 Areas of light- moderate corrosion noticed on all seats, mainly at welded areas Continue to monitor for worsening conditions annually. 2 Not all areas inspected due to access Set up a way to inspect all stanchions to assess condition 3 Coating failure Recoat all areas of failed coating Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 8 of 39 Platform Spurr 2024 Inspection Results Summary Task 7- Brucker DavitsItem Observation Recommendations 1 Through wall, and heavy, corrosion found on floor beams under davit Remove and repair all areas containing heavy, or through wall, corrosion 2 Rope used as a barrier to prevent people from falling off platform Replace and find a more permanent solution for a barrier 3 General light corrosion Continue to monitor annually Platform Spurr 2024 Inspection Results Summary Task 8- Crane FoundationItem Observation Recommendations 1 Area of moderate corrosion SE corner of structure Remove and recoat corrosion 2 Light general corrosion Continue to monitor annually Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 9 of 39 Platform Spurr 2024 Inspection Results Summary Task 9- Flare BoomItem Observation Recommendations 1 Section of missing grating Replace area of missing grating 2 Light general corrosion Continue to monitor annually Platform Spurr 2024 Inspection Results Summary Task 10- GeneralItem Observation Recommendations 1 General light-moderate corrosion noticed throughout deck beams for drilling deck Continue to monitor on a annual basis for worsening conditions 2 General coating failure throughout all deck beams for drilling deck Recoat areas of failed coating 3 Leaking roof in generator room and well rooms and top deck (covered with pallets)Fix all leaks in roof 4 Heavy corrosion in well rooms and generator room Clean and repair all holes in the roof 5 Not all areas inspected due to access, asbestos, and equipment in the way Get proper equipment and training to inspect in asbestos area Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 10 of 39 3.Topside Inspection Data Sheets 3.1 Deck Beam- Drilling Deck COMPONENT(S):Deck Beams- Drilling Deck INSPECTION DATE:9/16/24 INSPECTED BY: Alex Forster PLATFORM:Spurr LOCATION:South Breeze Way REPORT NO.:Task 1 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Beams supporting the deck on the drilling level Varies depending on location Carbon Steel LOW TEMP STEEL: API RP 2SIM First Edition, November 2014 None STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD: Unknown Unknown CRITICAL MEMBER LIST: None LEVEL I (VISUAL) Annual NA OBSERVATIONS:Light to moderate corrosion noticed throught platform on a majority of beams, along with coating failure. Areas of heavy corrosion found in well rooms an generator room where roof is leaking. ACTION ITEMS:Fix leaking roof, as well as areas of heavy corrosion. INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General Visual Inspection General Visual Inspection Not required Not required NOTES: I RECOMMENDATIONS:Fix all areas of heavy corrosion. Re coat all areas of failed coating. Continue to monitor areas of light to moderate corrosion for worsening conditions. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 11 of 39 Picture of Well Room 1A deck beams showing coating failure and light corrosion. Picture of leaking roof in generator room below crane Picture of heavy corrosion in generator room Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 12 of 39 3.2 Deck Beams- Production Deck COMPONENT(S): Deck Beams Production Beck INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: South breeze Way REPORT NO.: Task 2 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Beams supporting the production level varies depending on location Steel LOW TEMP STEEL: API RP 2SIM None STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD:Unknown Unknown CRITICAL MEMBER LIST: None LEVEL I (VISUAL) Annual N/A OBSERVATIONS:Heavy corrosion noticed on supports for the living quarters and production area. As well as, through wall corrosion found at area below brucker. I was only able to inspect a small portion of all the beams because of access. ACTION ITEMS: Repair through wall corrosion and areas of heavy corrosion. INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:Inspect areas that were not inspected, a boat or ropes may be needed. Come up with a repair plan for through wall corrosion, and areas of heavy corrosion. Continue to monitor all areas for worsening conditions. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 13 of 39 Support under well room 3. Water collecting and corroding where it pools. Unable to inspect all supports under well rooms due to access. Heavy corrosion was visible on beams under living quarters. This was inspected from a distance greater than 20’. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 14 of 39 3.3 Skid Beams COMPONENT(S): Skid beams on top deck INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Top Deck REPORT NO.: Task 3 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) None OBSERVATIONS:light - moderate corrosion noticed on all areas of exposed skid beams. Areas found where water is not draing off of roof which results in beams sitting in standing water. Much of the beams were not inspected due to equipment and buildings placed on top of them.I was not able to inspect areas below the roof because of asbestos ACTION ITEMS:Water drainage on roof INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:Get water to drain in areas where it is pooling. Continue to moitor annually areas of corossion for worsening conditions Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL) Annual INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Load bearing horizontal beams on the top deck, used for support or transporting heavy loads. Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD: Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 15 of 39 light-moderate corrosion noticed in generator room on skid beam. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 16 of 39 3.4 Trusses- Production Deck COMPONENT(S): Trusses- Production level INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Production Deck REPORT NO.: Task 4 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S)None OBSERVATIONS:Coating failure noticed throughout platform. Moderate- heavy corrosion noticed where trusses and columns intersect with floor in all rooms. Areas of standing water leave trusses and columns sitting in water and resulting in corrosion ACTION ITEMS:Areas of heavy corrosion and water drainage. All areas of coating failure. INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:Fix areas of heavy and moderate corrosion. Drain water where it is pooling, this may only take unclogging drains. Recoat areas of failed coating. Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL)Annual INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Framework supporting overhead structure on the production level. Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD: Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 17 of 39 Moderate-heavy corrosion found at all intersections of trusses and floor in well room 3A Well room 1A moderate corrosion noticed on flanges and at intersection with floor Another picture depicting heavy corrosion at floor intersection in well room 1A Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 18 of 39 3.5 Support Stanchions- Top Structure COMPONENT(S): Support Stanchions INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Below Production Deck REPORT NO.: Task 5 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Upright support holding the top structure to the legs or beam tanks Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD:Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL) Annual None OBSERVATIONS:All of these were inspected from a distance because of access. Light - moderate corrrosion were noticed at all locations, espically at welds.Not all were inspected because of access. ACTION ITEMS: If wanting a better pitcture of how all supports look, a plan will need to be established to inspect all supports that are not visable to just walking around INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:Continue to monitor for worsening conditions. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 19 of 39 Support for well room 2, moderate corrosion. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 20 of 39 3.6 Helideck Structure- Top Deck COMPONENT(S): Helideck and support structure INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Top Deck REPORT NO.: Task 6 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Upright structure supporting the heli deck, as well as the helideck Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD:Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL) Annual None OBSERVATIONS:Areas of moderate corrosion found on deck underside, supports, and floor beams. Fencing surrounding helideck is beginning to fail. ACTION ITEMS: Fix fencing, as well as address corrosion INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:Continue to monitor for worsening conditions. Remove corrosion and recoat in areas of moderate corrosion. Fix fencing that is beginning to fail around deck Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 21 of 39 Fencing beginning to come unconnected to its support. Found in multiple locations. Moderate corrosion found on beams under helideck loading area, as well as on support channel’s for the staircase where the stairs come into contact with the top deck. Moderate corrosion found on underside of decking, as well as floor beams, and supports. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 22 of 39 Connection points of support structure to floor beams, light to moderate corrosion. Not able to inspect all points because of access. Picture showing areas of moderate corrosion on helideck cantilever Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 23 of 39 3.7 Brucker Davits COMPONENT(S): Brucker Davits INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Lower level west-behind galley REPORT NO.: Task 7 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Structures to support bruckers for lifting and storage Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD:Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL) Annual None OBSERVATIONS:General light corrosion on davit. Through wall and heavy corrrosion on supports under grating for davits. Rope used as a barrier. ACTION ITEMS: Through wall corrosion repair, replace rope as barrier. INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:remove and repair all areas containing heavy corrosion, as well as through wall corrosion, on beams for support under davit. Find a more permanent barrier, other than rope. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 24 of 39 Through wall, and heavy, corrosion found on floor beams under davit. Moderate corrosion on beams supporting Brucker, NE side Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 25 of 39 3.8 Crane Foundation COMPONENT(S): Crane Foundation INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Top Deck South REPORT NO.: Task 8 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S)None OBSERVATIONS:An area of moderate corrosion was found in the SE corner of the foundation ACTION ITEMS: None INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS:Remove and recoat area of moderate corrosion Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL)Annual INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA Structures and foundation that support the crane Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD: Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 26 of 39 Area of moderate corrosion in SE corner of crane foundation Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 27 of 39 3.9 Flare Boom COMPONENT(S): Flare Boom INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: North Production Deck REPORT NO.: Task 9 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA All structures relating to the flare boom Unknown Steel LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD: Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL)Annual None OBSERVATIONS:Light general corrosion found through out. A section of misssing grating where flare attaches to structure. ACTION ITEMS: Replace missing grating INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS: Replace missing grating. Continue to monitor annaully for worsening conditions Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 28 of 39 Area of missing grating on flare boom Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 29 of 39 3.10 General COMPONENT(S): General INSPECTION DATE: 9/16/24 INSPECTED BY: Alex Forster PLATFORM: Spurr LOCATION: Entire platform REPORT NO.: Task 10 DESCRIPTION: DIMENSIONS: MATERIALS: MEMBER JOINTS:WELDED BOLTED SUPPORTS:WELDED BOLTED SCOPE OF INSPECTION:LEVEL CORROSION DEFORMATION WELD FLAW BOLTED JOINTS A) VISUAL: FATIGUE DAMAGE THICKNESS MEAS.JOINTS: SCHEDULE MEMBERS B) NDE: JOINTS: LEVEL II (VISUAL AND NDE OF CRITICAL ITEMS):MEMBERS YEAR(S) INSPECTION NOTES TOPSIDE STRUCTURAL COMPONENT INSPECTION RECORD COMPONENT DATA PICTURE OR SKETCH OF COMPONENT INSPECTION CRITERIA General observations that are not covered in other catagories Unknown Unknown LOW TEMP STEEL: API RP 2SIM Unknown STANDARD: CRITICAL JOINT LIST: DESIGN LOAD: ACTUAL LOAD: Unknown Unknown CRITICAL MEMBER LIST:Unknown LEVEL I (VISUAL)Annual None OBSERVATIONS: A hole in the roof of the top deck with an approximate radius of 4 feet covered with pallets, this is just to the west of the stairs going to the generator room. Another hole was founf in the roof of well room 3A. Floors with Heavy corrosion found in multiple areas see pictures. Was not able to inspect insid living or production area because of asbestos. Moderate to heavy corrosion found on walkways see pictures.Clogged drains throughout platform ACTION ITEMS: Fix holes in well room 3A and top deck. Remove and repair heavy corrosion on floors and walkways, including stairs. Fix all doors that do not close. Unclog all drains and assess water pooling situation. See pictures for areas that would need attention INSPECTION PERFORMED: LIST OF JOINTS/MEMBERS INSPECTED General visual inspection performed General visual inspection performed Not required Not required NOTES: RECOMMENDATIONS: Fix all holes in roofs. Unclog any drains that are clogged, and re-evaluate where water is pooling. Remove and fix all areas of heavy, or through wall corrosion, in floors and walkways. Re-coat all areas of failed coating. Get safety equipment and people with correct training to inspect areas with asbestos. Fix doors that do not close, well room 2A. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 30 of 39 General notes I took while in the field doing my inspection. Moderate corrosion found on floor beam of walkway to well room 1A Impact damage 8” radius x ½” off set on walkway outside of well room 2A. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 31 of 39 Through wall corrosion found at NE corner of well room 3A Generator room holding water Pipe deck next crane holding water Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 32 of 39 Handrail to the west of the crane being held in position by a ratchet strap Support for walkway outside of living quarters. The hardware has moderate corrosion Hole in floor of top deck. I also noticed plywood was being placed over the east side of the top deck. I assume this is to either cover holes or spread weight so more holes are not created. I was not able to inspect inside the building because of asbestos. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 33 of 39 Another picture of the hole on the top deck. Approximately 3’ radius. A hole in the roof of well room 3A in the SW corner, dimensions approximately 16” x 14” More small holes in well room 3A that allow water to come through. I noticed multiple holes in the roof in a multitude of locations. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 34 of 39 Well room 3A with standing water ¼”-1” deep. Heavy corrosion noticed underneath water all over. Handrail on stairs in the breeze way going to well room 3A, depicting heavy corrosion. Stairs in breeze way going to well room 3A showing through wall corrosion Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 35 of 39 Walkway in the south breeze way showing heavy corrosion on the floor beams of the grating Underside of floor in well room 1A, heavy corrosion. Walkway in south breeze way to production area. Welded barricade to prevent people from entering, as well as signs saying, “caution asbestos”. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 36 of 39 Stairway going to breeze way from well room 1A. Heavy corrosion at base where handrail connects to walkway Well room 1A floor depicting heavy corrosion, bubbling, and flaking. SE doorway to stairs leading to breeze way Well room 1A, west side of room. Floor depicting moderate corrosion Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 37 of 39 Door in well room 2B will not stay latched closed. East door Door in well room 2B unable to close, also though wall corrosion on bottom. North door Well room 2B depicting moderate to heavy corrosion on the floor. Corrosion builds up approximately 1/4'”-1/2” thick Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 38 of 39 Clogged drain in well room 2B. I didn’t find any drains on this platform that were not clogged. Document Title: Spurr 2024 Topside Survey Report Number.: Spurr 24 Revision Date: 09/24/2024 Revision: 00 Page 39 of 39 Appendix A.Repair Program – Priority 1 1.Leaking roof Generator room (Task 1, Item 3) 2.Heavy corrosion on floors (Task 1, Item 4) 3.Through wall corrosion (Task 2, Item 2) 4.Standing water (Task 6, Item 3) 5.Through wall corrosion (Task 7, Item 1) 6.Leaking roof (Task 10, Item 3) 7.Heavy corrosion (Task 10, Item 4) Appendix B.Repair Program – Priority 2 1.Water pooling (Task 3, Item 2) 2.Inspect area with asbestos (Task 1, Item 5) 3.Inspect all areas (Task 2, Item 3) 4.Inspect all areas (Task 3, Item 3) 5.Water pooling (Task 4, Item 1) 6.Moderate to heavy corrosion (Task 4, Item 2) 7.Inspect all seats (Task 5, Item 2) 8.Fix fencing (Task 6, Item 1) 9.Moderate corrosion (Task 6, Item 2) 10.Moderate corrosion crane (Task 8, Item 1) 11.Missing grating (Task 9, Item 1) 12.Asbestos (Task 10, Item 5) Appendix C.Repair Program – Priority 3 1.Light corrosion (Task 1, Item 1) 2.Coating failure (Task 1, Item 2) 3.Light corrosion ((Task 2, Item 1) 4.General corrosion (Task 3, Item 1) 5.Coating failure (Task 4, Item 3) 6.Light to moderate corrosion (Task 5, Item 1) 7.Coating failure (Task 5, Item 3) 8.Inspect entire structure (Task 6, Item 4) 9.General corrosion (Task 6, Item5) 10.Roped barrier (Task 7, Item 2) 11.General corrosion (Task 7, Item 3) 12.General corrosion (Task 8, Item 2) 13.General corrosion (Task 9, item 2) 14.Light Corrosion (Task 10, Item 1) 15.Coating Failure (Task 10, Item 2) 10 08/21/2025 Commissioners – Jessie Chmielowski and Greg Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 Subject: Proposed update of Hilcorp Alaska, LLC Other Order 193 – Cook Inlet Offshore Well P&As Dear Commissioner Chmielowski and Commissioner Wilson, Hilcorp has begun reservoir abandonments of the MGS oil pool in seven wells on the Baker Platform. This activity is in support of Other Order 193 (OO-193) as discussed in our annual review meeting on February 19, 2025. Since the issuance of OO-193, Hilcorp has modified the original timeline and prioritization of P&A activity through annual P&A plan updates discussed with the AOGCC. This request is to formally update OO-193 to reflect the current and planned future P&A activity as it relates to the order. Background OO-193 was issued on May 19, 2022 and approved Hilcorp’s request to reprioritize the P&A plans for wells on the Baker, Dillon, and Spurr platforms. Wells on the Dillon platform were subsequently abandoned in 2022 and 2023. On November 28, 2023, Hilcorp met with the AOGCC to discuss the 2024 Cook Inlet P&A program. Hilcorp and AOGCC mutually agreed to focus the near-term efforts on abandonment of the MGS Oil Pool in wells on the Baker platform. Hilcorp also proposed prioritizing P&A of wells on the MGS “C” platform ahead of the Spurr. AOGCC Commissioners agreed that Hilcorp’s P&A plans were consistent with the risk associated with the wells on these platforms. In 2024, Hilcorp abandoned the MGS Oil Pool on three wells on the Baker platform and one additional well was abandoned but is awaiting final testing of the abandonment plug. On February 19, 2025, Hilcorp met with the AOGCC to confirm the focus of the 2025 P&A campaign would be the remaining MGS oil pool abandonments on the Baker platform except for two injection wells to be left open for future fluids disposal. Additional discussions with the AOGCC in 2025 clarified abandonment requirements of the MGS Oil Pool. AOGCC and Hilcorp also agreed to defer abandonment of the MGS ST 17595 13 due to its existing downhole configuration. 2025 Cook Inlet P&A Plans As of August 21, 2025, Hilcorp has executed cement plugs for abandonment of the MGS Oil Pool in seven Baker platform wells per the approved sundries. These wells include MGS ST 17595 6, 11, 20, 23, 28, 29 and 30. Final Hilcorp Alaska, LLC Trudi Hallet CIO Asset Team Lead 3800 Centerpoint Dr, Suite 1400 Anchorage, Alaska 99503 By Samantha Coldiron at 7:31 am, Aug 22, 2025 testing of the abandonment plugs will occur in the coming days for these seven wells and for MGS ST 17595 5, which was abandoned in 2024. Future OO-193 P&A Prioritization Annual well P&A campaigns will continue to be conducted during the CIO ice-free season on a platform-by-platform basis until all wells on the MGS C Platform, Spurr Platform and Baker Platform are either P&A’d or redeveloped. As of summer 2025, future P&A work is prioritized below. The order of abandonments may be adjusted as risk, development opportunities and resource requirements are better understood. Any adjustment to this order will be updated through Annual P&A plan updates due by November 15th of each year per OO-193. 1) MGS “C” Platform – Begin 2026 In April of 2021 the gas pipeline running between MGS “A” platform and the MGS onshore facilities developed a leak. As a result of this pipeline failure and the pipeline configuration in Middle Ground Shoal, production from both platforms “A” and “C” had to be shut in. Hilcorp completed an economic evaluation in late 2021 and determined that the resource accessible by platform “A” could justify the pipeline repair in conjunction with other development projects or more favorable market conditions. In no scenario did it make commercial sense to return the MGS “C” platform to production based on the remaining reserves accessible by its wells. MGS “C” platform has ~24 long-term shut-in wells. These wells are shut-in at surface with wellbore perforations open to the reservoir. In contrast, the Spurr Platform wells were previously under suspended status and have subsurface isolation preventing potential flow or pressure from the reservoir to surface. For these reasons MGS “C” platforms are prioritized for abandonment ahead of Spurr or Baker. Experience with previous well abandonment campaigns on the Dillon and Baker platforms indicate that abandonment of all ~24 wells will likely require two seasons including time to mobilize to the platform, prepare the platform for well work and execute all well interventions during ice free seasons. 2) Spurr Platform P&A of the Spurr platform wells is planned after MGS “C” well P&A is completed and once timing, resources, and plans for future gas development (including Spurr, Baker, and MGS A) are better understood. 3) Baker Platform Following the 2025 P&A campaign only three Baker platform wells are expected to remain open in the MGS Oil Pool. Two remaining injection wells, MGS ST 17595 16 & MGS ST 17596 17, are planned to be left open for fluids disposal under AIO 7.004 until the conclusion of P&A activity on the platform. Additionally, reservoir abandonment of MGS ST 17595 13 was deferred from the 2025 program and will be addressed in conjunction with future abandonment or development of the MGS Gas Pool on the platform. P&A and/or redevelopment of any remaining Baker Platform wells is planned to commence after MGS “C” and Spurr platform work. Request To formally update OO-193 to reflect current plans, Hilcorp requests that Conditions # 1 and #2 of OO-193 are modified to read: 1. Well P&As on the MGS C platform will begin in 2026 and are expected to take two seasons to complete. P&A on the Spurr platform is targeted to begin after completion of the MGS C platform. Finally, the remaining wells on the Baker platform will either be developed or be P&A’d following the MGS C and Spurr platform P&A work. 2. Completed If you have any questions, please contact me at (907)777-8323. Sincerely, Trudi Hallet CIO Asset Team Lead cc: Bryan McLellan Mel Rixse Digitally signed by Trudi Hallett (1231) DN: cn=Trudi Hallett (1231) Date: 2025.08.21 14:59:10 - 08'00' Trudi Hallett (1231) 9 From:McLellan, Bryan J (OGC) To:Dan Marlowe Cc:Wyatt Rivard; casey.morse@hilcorp.com Subject:MGS Oil Pool Abandonment and Plugging - AOGCC clarification and expectations Date:Friday, March 21, 2025 3:22:00 PM Dan, The intent of this email is to provide AOGCC’s expectations for plugging and abandonment of significant hydrocarbon zones within the Middle Ground Shoal (MGS) Oil Pool in accordance with 20 AAC 25.112. Background: Conservation Order 26 (August 4, 1966) Rule 3 designated 7 MGS Oil Pools which correlate as follows to Pan American Corporation State 17595 #4 well: MGS Oil Pool A – 5300-5830’ MGS Oil Pool B – 5830-6100’ MGS Oil Pool C – 6100-6400’ MGS Oil Pool D – 6400-6750’ MGS Oil Pool E – 6750-7050’ MGS Oil Pool F – 7050-7375’ MGS Oil Pool G – 7375-9215’ CO 26 Rule 4 allowed for Permissible Commingling in the same wellbore from: MGS Oil Pools B, C and D MGS Oil Pools E, F and G CO 31 (October 19, 1966) updated the Permissible Commingling list of Rule 4 to specify that Pool A must be segregated: MGS Oil Pool A MGS Oil Pools B, C and D MGS Oil Pools E, F and G CO 44 (July 19, 1967) changed the boundary between Pools A & B, but did not change the commingling permissions. MGS Oil Pool A – 5300-5720’ MGS Oil Pool B – 5720-6100’ CO 44A (January 12, 2017) Combined MGS Oil Pools A-G into a single oil pool AOGCC regulation 20 AAC 25.112(c) states that “Plugging of cased portions of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous strata and are prevented from migrating into other strata or to the surface.” A stringent interpretation of AOGCC’s regulation would require cement across every perforated stratum. The MGS Oil Pool, of almost 4,000’ in length per CO 44A, contains many perforated strata. However, the AOGCC will instead consider the plugging and isolation of the significant hydrocarbon bearing zones as meeting the intent of the regulation. For the purpose of plugging and abandoning the significant hydrocarbon bearing zones in the MGS Oil Pool, the AOGCC recognizes three separate strata aligning with CO 44 Rule 3’s Permissible Commingling Rule. These strata, depth referenced to Pan American Corporation State 17595 #4 well, are: 1. MGS Oil Pool A - 5300 – 5720’ MD 2. MGS Oil Pools B, C & D – 5720 – 6750’ MD 3. MGS Oil Pools E, F & G – 6750 – 9215’ MD. Each of these separate strata must be plugged separately in accordance with 20 AAC 25.112. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 1 Hilcorp Alaska, LLC Casey Morse Well Integrity Engineer 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 August 19, 2024 Commissioner Chmielowski and Commissioner Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 VIA EMAIL Subject: Docket Number: OTH-24-026 P&A of Middle Ground Shoal Wells on Baker Platform Dear Commissioner Chmielowski and Commissioner Wilson, This letter is in response to the letter received on July 30, 2024. In its letter, AOGCC requested Hilcorp to submit: 1. A list of significant gas sands within the MGS Gas Pool for wells Baker 4 (PTD 1640060), Baker 11 (PTD 1670170), and Baker 23 (PTD 1840110). 2. The reasoning and cutoffs for determining which hydrocarbon zones are significant. 3. A proposal to isolate significant hydrocarbons to their indigenous strata. In response to each item listed above: 1. Hilcorp has included the attached annotated cross-section and perforation track key. The stratigraphic cross- section includes seven wells (BA-11/BA-23/BA-04/BA-18/BA-14/BA-27/BA-32), the three wells outlined in this letter plus an additional four wells that are important in understanding the presence of gas underneath the Middle Ground Shoal Baker platform. The cross-section is orientated south (left) to north (right) and here is a breakdown of the curves present and their respective tracks: x Index Track: Measured Depth (MD) x Track 1:Gamma Ray: “GR” (green)– Spontaneous Potential: “SP” (black) x Index Track: True Vertical Depth (TVD) x Perforation Track: – see attached key for color representations x Index Track: True Vertical Depth SubSea (TVDss) x Track 2: – Resistivity: “RESD” (black, shaded red at 10 ohms) – “RESM” (blue)– “RESS” (red) x Track 3: – Density Porosity : “DPHI” (black, shaded yellow at 12% porosity)–Neutron: “NPHI” (blue)– Sonic: “DTC” (orange) x Facies Track: Net Sand x Mudlog Track: Total Gas: “TLGS” x Comment Track: notes on perforated zones, plugs, etc. By Samantha Coldiron at 12:17 pm, Aug 20, 2024 2 Additionally, the space between wells is colored either grey, pink, or red. These colors help differentiate different zones across wells. x Grey = zone has not been perforated in any well x Pink = perforated in at least one well, no gas measured (no flow, wet, etc. - see comments) x Red = perforated in at least one well, successful gas measured (see comments) 2. Hilcorp identified various strata in the attached cross section with sellable quantities of gas produced from offset wells. Hilcorp did not consider other factors in its determination. No additional analysis was performed to determine why certain strata were perforated and tested without yielding sellable quantities of gas. Similarly, no additional analysis was performed to determine which strata might yield sellable quantities of gas that had not previously been perforated and tested in offset wells. The attached cross section illustrates that sellable quantities of gas may exist across most of the MGS Gas Pool. 3. Hilcorp submitted 10-403 applications for sundry approval to abandon the Baker 4, Baker 11, and Baker 23 in June of 2024. These applications detail procedures for abandonment of the wells. Sincerely, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC Phone: 1-907-777-8322 Email: Casey.Morse@Hilcorp.com Digitally signed by Casey Morse (11458) DN: cn=Casey Morse (11458) Date: 2024.08.19 15:55:05 - 08'00' Casey Morse (11458) Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.govJuly 30, 2024 CERTIFIED MAIL – RETURN RECEIPT REQUESTED 7017 2400 0000 5648 0640 Mr. Dan Marlowe Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Dear Mr. Marlowe: Re: Docket Number: OTH-24-026 Request for Information Plugging and Abandonment Sundry Applications Middle Ground Shoal Gas Pool During a meeting with Hilcorp Alaska, LLC (Hilcorp) at the Alaska Oil and Gas Conservation Commission (AOGCC) office on July 9, 2024, the AOGCC verbally requested an assessment of significant hydrocarbon zones within the Middle Ground Shoal (MGS) Gas Pool at Baker platform. The information is necessary for the AOGCC to consider approval of plugging and abandonment sundry applications of the gas pool and to ensure progress continues in 2024 toward the requirements of Other Order 193. Within 20 days of receipt of this letter Hilcorp is requested to submit: 1. A list of significant gas sands within the MGS Gas Pool for wells Baker 4 (PTD 1640060), Baker 11 (PTD 1670170), and Baker 23 (PTD 1840110). 2. The reasoning and cutoffs for determining which hydrocarbon zones are significant. 3. A proposal to isolate significant hydrocarbons to their indigenous strata. Docket Number: OTH-24-026 July 30, 2024 Page 2 of 2 This information request is made pursuant to 20 AAC 25.300. Questions regarding this request should be directed to Bryan McLellan at (907) 793-1226 or bryan.mclellan@alaska.gov. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: Casey Morse Trudi Hallett Juanita Lovett Matthew Petrowsky Christopher Stone Phoebe Brooks (AOGCC) Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.07.30 09:03:56 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.07.30 09:08:36 -08'00' 8 1 Hilcorp Alaska, LLC Casey Morse Operations Engineer 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 November 14, 2025 Commissioner Chmielowski and Commissioner Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 VIA EMAIL AND CERTIFIED MAIL Subject: Docket Number: OTH-22-005 2025 Cook Inlet Well P&A Report Dear Commissioners Chmielowski and Wilson, Please see the summary below of the 2025 Cook Inlet well plug and abandonment campaign. Hilcorp appreciates the recent and ongoing discussions with AOGCC Staff and Commissioners on this topic. Sincerely, Casey Morse Operations Engineer Hilcorp Alaska, LLC Phone: 907-777-8322 Email: Casey.Morse@Hilcorp.com By Samantha Coldiron at 1:14 pm, Nov 18, 2025 Digitally signed by Casey Morse (11458) DN: cn=Casey Morse (11458) Date: 2025.11.14 15:21:22 - 09'00' Casey Morse (11458) 2 2025 Platform Well Abandonment Campaign Operations to prepare the Baker platform for the 2025 P&A program began on July 7, 2025. Starting up the temporary camp after the shut-down through winter took several weeks. Rental equipment was mobilized to the platform at the end of July so brine could be mixed and ready for cement operations in early August. The platform remained fully staffed through August 26th. From that point forward, ongoing cleanup and equipment de-mobilization continued with intermittent support through September to winterize the facility. During the month of August, Hilcorp completed coil tubing interventions on the Ba-06, Ba-11, Ba-23, and Ba-30. Additionally, Hilcorp completed fullbore cement plugs on the Ba-20, Ba-23, Ba-28, Ba-29, and Ba-30. Following the completion of cement work for the oil reservoir abandonment, Hilcorp obtained CMIT’s and slickline tags on all the wells listed above as well as the Ba-05, which was cemented in 2024. Hilcorp performs monthly wellhead pressure monitoring and submits the pressure reports monthly to AOGCC for the Baker platform in accordance with OTH-21-019 (Revised). Pressures from the Baker wells impacted by 2025 activities are included below along with the specific well activities for reference. Hilcorp currently plans to dismantle the drilling derrick on MGS C Platform in 2026. This will allow for staging abandonment equipment on the top deck and streamline well abandonment activities. The platform derrick is currently not in service and will only hinder future P&A operations due to space constraints on the platform deck. Removing the derrick will not compromise Hilcorp’s ability to perform future well interventions. Hilcorp also plans to run slickline diagnostics on all shut-in wells on MGS C to inform P&A procedures for the following season. Preparation of the top deck is expected to occupy the platform resources (such as the cranes and camp) for most of the ice-free season next year, so it is unlikely the platform will be ready to support well abandonment work prior to winter conditions at the end of 2026. Structural Integrity Inspections & Platform Maintenance Routine inspections are conducted annually on Hilcorp’s Cook Inlet Offshore Platforms. Hilcorp’s structural integrity inspection program follows the guidelines of API RP 2SIM. The inspection frequency is determined considering variables such as Cook Inlet’s unique environment, results from pushover analyses, individual facility geometry (brace configuration, number of legs, etc.), damage and repair history, and the platform’s status as a manned or unmanned “lighthoused” facility. The inspection frequencies are reviewed and adjusted as needed annually based on the previous year’s inspection results. Inspections include the following: x Subsea Jacket Inspections x Splash Zone Leg Inspections x Cathodic Protection Surveys x Subsea Sonar Inspections x Topside Inspections In addition to the structural integrity inspections listed above, the functionality of critical systems is monitored, and equipment is repaired as necessary, at least once per month during routine visits to the “lighthoused” facilities. Routine monthly inspections include confirming functionality of the crane and critical power systems and ensuring cleanliness of decks for safe working surfaces. Inspections conducted in 2025 verified MGS-C to be structurally sound and all equipment to be in safe working condition to support planned P&A operations. 3 Lessons Learned from Baker in 2025 x Hilcorp greatly appreciates the AOGCC cooperation in approving sundries months in advance of this program. Hilcorp also appreciates the timely responses from AOGCC staff when changes to the approved programs arose. The difficulty of staffing and supporting these lighthoused facilities leaves little room to pivot plans based on feedback from the well condition or changes in the operations (i.e. stuck tools, shallow tag depths, lack of injectivity, etc.). AOGCC cooperation and timely response to these unpredictable well conditions aided the successful execution of this program. x Combination MITs on these large volume wellbores are difficult to stabilize to the inspector’s criteria within a reasonable amount of time. All CMITs exhibited stabilizing trends and pressure drops of less than 10%. Several CMIT’s did not meet the inspector’s criteria of showing less than 50% pressure drop in the subsequent 15-min intervals relative to the pressure drop in the prior 15-minute interval. It takes a couple hours to prep and perform a test. Conducting multiple tests or extending the pressure tests for hours ties up valuable resources (and AOGCC inspectors) for days with little added value. Instead of spending the extra time on these pressure tests, Hilcorp turned in 3 MIT’s at the conclusion of this program that were noted as “fail” per the inspector. The stabilizing pressure trends shown below give indication that the wells have integrity. Well-by-well Updates from Baker MGS ST 17595 5 (Baker 5) Hilcorp was unable to obtain a witnessed CMIT and tag after completing the cement work in 2024. On June 23, 2025, Hilcorp requested an extension to the sundry expiration date (324-367) to allow for performing the witnessed CMIT and tags in its 2025 program. AOGCC approved this request on the same day. On August 23, Hilcorp performed a CMIT on the LSxSSxIA with the following results and shown graphically below: Initial: 1702 psi 15-min: 1637 psi 30-min: 1616 psi 4 This CMIT was noted as a “pass” per the AOGCC inspector. Witnessed tags also confirmed cement depths in the long string and short string. Hilcorp submitted 10-407 on September 19 seeking closure of the above referenced sundry. MGS ST 17595 6 (Baker 6) On August 19, Hilcorp rigged up coil tubing to perform a cleanout run prior to cementing. Coil obtained a hard tag on the CIBP at 5753’ CTM per requirements of Sundry 325-262. Eline then obtained a correlated tag to confirm depth. After approval was received from AOGCC, Hilcorp pumped 10 bbls of cement at the CIBP. On August 24, CMIT was performed on the LSxSSxIA with the following results and shown graphically below: Initial: 1730 psi 15 minutes: 1711 psi 30 minutes: 1704 psi -200 0 200 400 600 800 1000 1200 1400 1600 1800 PSI G Elapsed Time hh:mm:ss Ba-5 - 23-Aug-25, 12:05:44, 1002 PSI G 5 This CMIT was noted as a “pass” per the AOGCC inspector. Witness was waived on the eline correlated tag performed on August 25. The tag depth correlated to 5104’. This depth did not comply with the conditions of approval included in Sundry 325-262. On August 26, Hilcorp requested approval to close the sundry as is based on the acquired tag depth. Hilcorp proceeded with submitting the 10-407 on September 19 for approval to close the sundry. AOGCC responded to Hilcorp’s email request on November 6 regarding the discrepancy in tag depth relative to the conditions of approval for Sundry 325-262. As noted in AOGCC response, the successful CMIT ensures satisfactory conditions for placing the well into Suspended status. MSG ST 17595 11 (Baker 11) While pumping the fullbore cement job on Ba-11 in 2024, the cement pump malfunctioned. Hilcorp was unable to obtain sufficient tags to diagnose the well prior to winterizing the platform at the end of the 2024 P&A campaign. A change to approved Sundry was agreed upon to perform a coil intervention on the short string in 2025. On August 16, Hilcorp rigged up coil tubing on the short string and cleaned scale down to a cement tag at 7242’ CTM. Eline then acquired a CBL to confirm top of cement in the IA at approximately 4,430’. After receiving approval from AOGCC to proceed with cement operations, Hilcorp placed a cement plug in the short string from 7230’. On August 23, slickline obtained tags in the short string and long string. CMIT was performed on the LSxSSxIA with the following results and shown graphically below: Initial: 2555 psi 15 minutes: 2476 psi 30 minutes: 2437 psi 0 200 400 600 800 1000 1200 1400 1600 1800 2000 PSI G Elapsed Time hh:mm:ss Ba-06 - 24-Aug-25, 04:50:49, 2330 PSI G 6 This CMIT was noted as a “pass” per the AOGCC inspector. On September 19, Hilcorp submitted a 10-407 requesting closure of Sundries 324-365 and 325-260. MGS ST 17595 13 (Baker 13) No further work was performed on the Ba-13 well in 2025. MGS ST 17595 20 (Baker 20) On August 14, Hilcorp pumped a fullbore cement reservoir abandonment plug. Pressures and return volumes were managed closely to ensure a successful placement of the cement into LS, SS, coil, and IA while injecting the required amount into the perforations per Sundry 324-403. On August 21, Hilcorp rigged up eline to acquire a cement bond log. That log confirmed top of cement in the IA at approximately 2050’. The CBL was conveyed to AOGCC digitally on September 12 as T40881. On August 24, AOGCC witnessed tags in the long string and coil tubing. CMIT was performed on the LSxSSxCTxIA with the following results and shown graphically below. This test was performed twice and initially held for 45 minutes to try and satisfy the inspector’s criteria of obtaining less than half the pressure drop in the second 15 minutes relative to the pressure drop in the first 15 minutes. Initial: 2240 psi 15 minutes: 2160 psi 30 minutes: 2112 psi 0 500 1000 1500 2000 2500 3000 PSI G Elapsed Time hh:mm:ss Ba-11 - 23-Aug-25, 01:19:26, 626 PSI G 7 This CMIT was noted as “fail” per the AOGCC inspector. Pressure loss was less than 10% over the 30-minute test, and the pressure exhibited a stabilizing trend as shown in the graph above. Hilcorp submitted a 10-407 on September 19 to close Sundry 324-403. MGS ST 17595 23 (Baker 23) In October 2024, while RIH with the CIBP on eline, the CIBP got stuck at 4500’. While working the tool string and pumping on the well, E-line pulled out of the rope socket and lost the tool string. 12 runs were made with slickline to try and recover the lost tools with no success. Hilcorp submitted a change to the approved sundry to continue the oil reservoir abandonment work in 2025. On August 10, 2025, coil tubing rigged up on the Ba-23. With coil tubing, Hilcorp was able to push the CIBP to the bottom of the tubing string, latch the CIBP setting tools, and set the plug at 8476’. Communication was confirmed between tubing and IA through the tubing punch above the CIBP. A fullbore cement plug was pumped down tubing. On August 24, slickline obtained a tag in the tubing with AOGCC witness, confirming good placement of cement from the fullbore cement plug. When pressuring up to attempt the CMIT, communication was observed between the IA and OA. A circulation rate was established, and a dye pill circulated to estimated leak depth of 305’. As a result, Hilcorp was unable to perform CMIT of TxIA. This hole in casing will need to be addressed as part of the shallow abandonment procedures. On September 19, Hilcorp submitted 10-404 to close Sundries 324-357 and 325-339. MGS ST 17595 28 (Baker 28) 0 500 1000 1500 2000 2500 PSI G Elapsed Time hh:mm:ss Ba-20 - 24-Aug-25, 02:31:01, 1339 PSI G 8 Hilcorp rigged up to circulate this well with 9.8ppg brine on August 4. Afterwards, the fullbore cement plug was pumped with success. The return volumes and pressures were carefully monitored and swapped from IA to SS and back IA to enable smooth operations and allow for the appropriate amount of cement to inject into the perforations while returning the designed volumes. This procedure and the mixed retardant blend kept the cement moving and prevented early setup. On August 23, slickline obtained tags on the LS and SS with AOGCC witness. CMIT was performed twice to satisfy passing criteria on the LSxSSxIA with the following results and shown graphically below: Initial: 2180 psi 15 minutes: 2202 psi 30 minutes: 1971 psi This CMIT was noted as a “pass” per the AOGCC inspector. On September 19, Hilcorp submitted a 10-404 requesting closure of Sundry 324-552. MGS ST 17595 29 (Baker 29) Hilcorp rigged up to pump the fullbore cement plug on August 21, and the job was pumped with success. The return volumes and pressures were carefully monitored and swapped from IA to SS and back IA to enable smooth operations and allow for the appropriate amount of cement to inject into the perforations while returning the designed volumes. This procedure and the mixed retardant blend kept the cement moving and prevented early setup. On August 24, slickline obtained tags on the LS and SS with AOGCC witness. CMIT was performed on the LSxSSxIA. This test was performed for 45 minutes to try and satisfy the inspector’s criteria of obtaining less than half the pressure drop in the second 15 minutes relative to the pressure drop in the first 15 minutes. The results are listed and shown graphically below: 0 500 1000 1500 2000 2500 PSI G Elapsed Time hh:mm:ss Ba-28 - 23-Aug-25, 10:05:35, 972 PSI G 9 Initial: 2151 psi 15 minutes: 2077 psi 30 minutes: 2032 psi 45 minutes: 1997 psi This CMIT was noted as “fail” per the AOGCC inspector. Pressure loss was less than 10% over the 30-minute test, and the pressure exhibited a stabilizing trend as shown in the graph above. On September 19, Hilcorp submitted a 10-407 requesting closure of Sundry 324-550. MGS ST 17595 30 (Baker 30) On August 9, Hilcorp rigged up coil tubing to lay in cement from the PBTD of this well. A tag was obtained at 10,410’ with confirmed sand / debris in the wellbore below. Approval was obtained from AOGCC to pump the cement plug from this depth in accordance with 20 AAC 25.112(c)(1)(C). Cement was placed through coil back to estimated cement top of 9,424’. On August 10, Hilcorp pump two sequential fullbore plugs to place cement into the long string and IA, then the coil tubing and short string. The long string was strategically overdisplaced to enable CBL for identifying top of cement in the IA. These jobs were pumped successfully. On August 13, eline obtained a CBL identifying top of cement at approximately 7,670’. The log was emailed to AOGCC and analysis of top of cement was confirmed on August 19 by AOGCC. On August 24, slickline obtained tags on the LS, SS, and coil tubing with AOGCC witness. CMIT was performed on the LSxSSxCTxIA. This test was performed twice to try and satisfy the inspector’s criteria of obtaining less than half the pressure drop in the second 15 minutes relative to the pressure drop in the first 15 minutes. The results are listed and shown graphically below: Initial: 2615 psi -500 0 500 1000 1500 2000 2500 PSI G Elapsed Time hh:mm:ss Ba-29 - 24-Aug-25, 11:01:25, 1003 PSI G 10 15 minutes: 2538 psi 30 minutes: 2474 psi This CMIT was noted as “fail” per the AOGCC inspector. Pressure loss was less than 10% over the 30-minute test, and the pressure exhibited a stabilizing trend as shown in the graph above. Hilcorp submitted a 10-407 on September 19 to close Sundry 324-403. MGS ST 17595 31 (Baker 31) Suspended well inspection was performed on July 20. Service Wells MGS ST 17595 16 and MGS ST 17595 17 (Baker 16 and 17) In accordance with AIO 7.004, Hilcorp performed successful MITs on both service wells prior to commencing disposal operations on May 15, 2024. Subsequent MITs were conducted on May 21, 2024. Below are tables of the volumes disposed of in each well through this season’s activity. Baker Platform Injection Well Report Well Ba-16 Date Time Fluid Type Fluid Source Tubing (LS) Pressure 9-5/8" Annulus Pressure 13-3/8" Annulus Pressure Rate BPM Total BBLS Total Vol Pumped -500 0 500 1000 1500 2000 2500 3000 PSI G Elapsed Time hh:mm:ss Ba-30 - 24-Aug-25, 08:48:48, 1454 PSI G 11 8/4/2025 17:00 FIW Ba-28 1250 40 140 2.3 91 91 8/5/2025 9:00 FIW Ba-28 1500 40 140 3.1 376 467 8/5/2025 15:00 FIW Ba-28 1750 40 140 3.3 573 1040 8/7/2025 7:00 Brine/FIW Ba-28 1400 40 140 3.2 263 1303 8/8/2025 8:00 FIW Ba-30 1600 40 140 3.1 797 2100 8/15/2025 14:30 Brine Ba-23 1500 40 140 3 211 2311 8/17/2025 16:30 Brine Ba-11 1500 40 140 3 250 2561 8/19/2025 15:30 Brine Ba-6 1500 40 140 3.5 232 2793 8/25/2025 0:00 Brine/FIW Ba-29 1500 40 140 3.5 641 3434 Pressures from Baker Wells Impacted by 2025 Activities 12 13 14 15 16 7 1 Hilcorp Alaska, LLC Casey Morse Well Integrity Engineer 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 November 15, 2024 Commissioner Chmielowski and Commissioner Wilson Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 VIA EMAIL AND CERTIFIED MAIL Subject: Docket Number: OTH-22-005 2024 Cook Inlet Well P&A Report Dear Commissioners Chmielowski and Wilson, Please see the below summary of the 2024 Cook Inlet well plug and abandonment campaign. Hilcorp appreciates the recent and ongoing discussions with AOGCC Staff and Commissioners on this topic. Sincerely, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC Phone: 1-907-777-8322 Email: Casey.Morse@Hilcorp.com 2 2024 Platform Well Abandonment Campaign Operations to prepare the Baker platform for the P&A program began on April 24, 2024. Starting up the temporary camp after the shut-down through winter took several weeks. A full crew staffed the platform starting May 14 to begin installing all P&A ancillary facilities (tanks, pumps, cement silos), installing circulating hoses to the wells, and preparing the disposal wells for operations. Work was conducted through the summer utilizing one crew with scheduled 14 days on and 7 days off. Well diagnostics began on May 16 to inform the scope of the sundries. Diagnostic work progressed through late June on the 12 wells identified for 2024 scope. Hilcorp began submitting 10-403 sundry requests for well abandonments starting on June 19. With one approved sundry, Hilcorp completed the cement work on Baker 5 on July 2nd, which was the last day of the crew’s 14-day shift. The crew took days off until July 16 when the second sundry was approved. Once completed with that approved work, the crew departed the Baker platform until additional sundries were approved in mid-September. Work continued on the remaining approved sundries until mid-October. The crew began rigging down tanks, cement silos, and other rentals and equipment susceptible to freezing on October 13. All critical equipment was removed, the temporary camp winterized, and the platform vacated for the season on October 16. Hilcorp currently plans to complete the P&A work on the remaining Baker wells as previously proposed in 2025. Upon completion, Hilcorp intends to begin work on the MGS C well abandonment. This will require dismantling of the drilling rig and mud pits on the C platform in order to stage the cementing equipment on the deck of the platform. Hilcorp plans to submit abandonment sundries and seek approval of the well work procedures prior to initiating the facility work on MGS C. Hilcorp intends to perform the well abandonment work on the Spurr platform following the completion of work on Platform C. Routine inspections were conducted on the Spurr through 2024. Hilcorp’s structural integrity inspection program follows the guidelines of API RP 2SIM. The inspection frequency is determined considering variables such as Cook Inlet’s unique environment, results from pushover analyses, individual facility geometry (brace configuration, number of legs, etc.), damage and repair history, and the platform’s status as a manned or unmanned “lighthoused” facility. The inspection frequencies are reviewed and adjusted as needed annually based on the previous year’s inspection results. Inspections include the following:  Subsea Jacket Inspections  Splash Zone Leg Inspections  Cathodic Protection Surveys  Subsea Sonar Inspections  Topside Inspections Based on current findings, there is no identifiable risk differential between the integrity of the surface facilities at the Spurr Platform and Hilcorp’s other Cook Inlet facilities. Lessons Learned from Baker in 2024  The cement blend develops gel strength when not subjected to shear. It was identified that during longer / higher volume cement jobs, the cement would have sufficient time to develop gel strength while sitting static in the sump on the suction side of the pump. This can cause a deadhead in the pump suction. To overcome this 3 issue, the best practice going forward will be to pause the job every 100 bbls during cementing to flush the sump pump and prevent this deadhead effect. This problem gets exacerbated when no back-up pump is available on the platform. This preventative flush procedure was employed successfully on the Baker 25RD. Well-by-well Updates from Baker MGS ST 17595 4 (Baker 4) Hilcorp submitted the 10-403 sundry request for the Baker 4 on June 20. The intent of this sundry was to plug and abandon the Baker 4 to surface. On August 21, AOGCC requested the sundry be withdrawn and resubmitted to include coil tubing work to fish tools from the tubing and lay in a cement plug below the end of tubing and only abandon the MGS Oil Pool. Hilcorp submitted the new 10-403 on September 5 and received approval on September 10. On September 19, coil tubing was mobilized and rigged up on the Baker. BHA #1 cleaned debris from the tubing down to the fish top at 5221’. BHA #2 was able to latch the fish and bring the stuck tools to surface except for the AD-2 stop. BHA #3 cleaned up the top of the AD-2 stop. BHA #4 was able to spear the stuck AD-2 stop and recover it. BHA #5 washed down to 7744’. BHA #6 laid in 8 bbl of 14 ppg cement at 7742’ to intended cement to of 7500’. On October 8, AOGCC witnessed tag in the tubing with a 2.5” OD bailer at 7539’. Witnessed CMIT was successful (initial: 2409 psi, 15 min: 2404 psi, 30 min: 2404 psi). MGS ST 17595 5 (Baker 5) Hilcorp submitted the 10-403 sundry request for the Baker 5 on June 21. The intent of this sundry was to plug the MGS Oil Pool and suspend this well for future evaluation of gas potential either through sidetrack or recompletion. This sundry was approved on July 1. On July 1, circulation was confirmed down LS and up IA and SS to displace the well from FIW to 9.8 ppg brine. On July 2, Hilcorp pumped 304 bbls of 13.7 ppg cement down LS up IA, getting 280 bbls of returns at 2.5bpm, 0 psi (24 bbls squeezed into perforations). Returns were swapped to the SS, and the LS pressured up to 1500 psi after 3bbls. Decision was made to drop wiper ball and displace 46 bbls 9.8 ppg brine down LS taking additional returns out IA w/ 9.8 ppg brine, shut in LS w/ 1125 psi on it. Calculated TOC in LS 5200', in IA 1015'. On July 3, the SS was pressure tested to 1600 psi (initial: 1600 psi, 15 min: 1580 psi, 30 min: 1580 psi). CBL was performed on the LS on October 5. E-line tagged at 5240’ in the LS, and cement top was identified at 250’ in the IA. Slickline rigged up on the SS on October 10 to acquire a tag. After working through scale for a day, slickline tagged up and returned a bailer with contaminated cement at 5740’ on October 11. With boat and crew availability, the decision was made to rig down for the winter prior to conducting witnessed MIT and tags. That work will need to be performed before conducting the initial suspended well inspection. MGS ST 17595 6 (Baker 6) Hilcorp submitted the 10-403 sundry request for the Baker 6 on July 8. The intent of this sundry was to plug the MGS Oil Pool and suspend this well for future evaluation of gas potential either through sidetrack or recompletion. Additional diagnostics were performed on July 22 to confirm injectivity into the gravel pack per request of AOGCC. On September 19, AOGCC informed Hilcorp that the procedure would not be sufficient to isolate the MGS Oil Pool. MSG ST 17595 11 (Baker 11) 4 Hilcorp submitted the 10-403 sundry request for the Baker 11 on June 21. The intent of this sundry was to plug and abandon the Baker 11 to surface. AOGCC approved the sundry on September 12 with only the abandonment of the MGS Oil Pool. On October 1, the well was bled down and displaced to 9.8 ppg brine. On October 2, 14 ppg cement was pumped down the LS intermittently while fighting pump issues. A total of 247 bbls cement were pumped with partial returns up the IA. 155 bbls of brine were returned from the IA during pumping operations. Ultimately, the pump stopped working. The suction side of the pump had valves stuck to seats. After cleaning and reassembling the suction side of the cement pump, it function-tested successfully and was capable of circulating on itself. Several attempts were made to establish injection down LS, SS, and IA with no success. Opened up the SS and pressured up to 2000 psi trying to get returns on IA, bled down and repeated 15 times with no success. Cement top was observed 4’ below the tree on the LS. Based on volumes pumped and circulated, estimated cement top in the IA would be ~4600’ with 92 bbls squeezed into the perforations. On October 7, slickline made several attempts to acquire a cement tag in the SS. Repeated attempts encountered scale and restricted downward progress beyond 6198’. No cement was encountered, and the tags were unreliable. The decision was made to rig down for the winter prior to conducting witnessed MIT and tags. Hilcorp plans to submit a request for change to approved permit to complete the work on this sundry. MGS ST 17595 13 (Baker 13) Hilcorp submitted the 10-403 sundry request for the Baker 13 on September 13. The intent of this sundry was to plug the MGS Oil Pool. On September 19, AOGCC informed Hilcorp that the procedure would not be sufficient to isolate the MGS Oil Pool. MGS ST 17595 20 (Baker 20) Hilcorp submitted the 10-403 sundry request for the Baker 20 on July 15. AOGCC responded with questions and requests for additional diagnostics on July 26, July 29, September 9, and September 12. Hilcorp provided responses and completed additional diagnostics. All information was submitted back to AOGCC on September 30. On October 4, AOGCC provided examples of two different procedures to satisfy concerns with zonal isolation in the MGS Oil Pool. No further action was taken. MGS ST 17595 23 (Baker 23) Hilcorp submitted the 10-403 sundry request for the Baker 23 on June 19. The intent of this sundry was to plug and abandon the Baker 23 to surface. AOGCC approved the sundry on September 6 with only the abandonment of the MGS Oil Pool. On October 5, E-line ran a GRJB to confirm drift for the CIBP to 8500’. While RIH with the CIBP, the CIBP got stuck at 4500’. While working the tool string and pumping on the well, E-line pulled out of the rope socket and lost the tool string. 12 runs were made with slickline to try and recover the lost tools with no success. Hilcorp plans to present a change in the procedure for this sundry to continue work next season. MGS ST 17595 25RD (Baker 25RD) Hilcorp submitted the 10-403 sundry request for the Baker 25RD on May 29. This sundry was withdrawn and replaced with a new sundry request on June 20. AOGCC responded with questions and requests for additional diagnostics on June 24, June 26, July 1, September 9, and September 12. Hilcorp subsequently withdrew that sundry and submitted a 5 replacement sundry on September 12. The intent of this sundry was to plug the MGS Oil Pool. The sundry was approved on September 17. On October 3, Hilcorp rigged up circulating equipment and began displacing the FIW to 9.8 ppg brine. It took 3 days to effectively displace the well to brine. On October 6, 14 ppg cement was pumped down the LS with returns up the IA. Cement was pumped until 67 bbls of returns surfaced up the IA. Returns were swapped to the SS while continuing to pump 14 ppg cement. 17 bbls of returns surfaced up the SS. The SS and IA were then closed, and 66 bbls of cement were squeezed into the perfs. The IA was opened again, taking additional returns up the IA until sufficient cement volume was pumped, fluid was swapped to brine for displacement, and a total of 61 bbls were returned up the IA at the end of the 48 bbl displacement volume. This placed estimated top of cement at 5500’ in the LS, SS, and IA. On October 7, slickline tagged cement in the LS with a 2.5” bailer at 5423’. On October 8, AOGCC witnessed slickline tag of the LS at 5424’ and SS at 5549’ with 2.5” bailer, and both returned 2 cups of contaminated cement in the bailer. Combo MIT was performed with AOGCC witness to >1925 psi per sundry (initial: 2111 psi, 15 min: 2069 psi, 30 min: 2039 psi, 45 min: 2014 psi, 60 min: 1991 psi). AOGCC approved as good test. MGS ST 17595 28 (Baker 28) Hilcorp submitted the 10-403 sundry request for the Baker 28 on September 24. The intent of this sundry was to plug the MGS Oil Pool. AOGCC approved the sundry on October 7 contingent upon Hilcorp providing evidence of injection occurring below the Kobe BHA. Hilcorp performed injectivity test and temperature log on October 10 and provided evidence supporting deep injectivity to AOGCC. No further work was performed on this sundry. MGS ST 17595 29 (Baker 29) Hilcorp submitted the 10-403 sundry request for the Baker 29 on September 24. The intent of this sundry was to plug the MGS Oil Pool. AOGCC has not responded to this sundry request. MGS ST 17595 30 (Baker 30) Hilcorp submitted the 10-403 sundry request for the Baker 30 on September 27. The intent of this sundry was to plug the MGS Oil Pool. AOGCC has not responded to this sundry request. MGS ST 17595 31 (Baker 31) Hilcorp submitted the 10-403 sundry request for the Baker 31 on July 5. The intent of this sundry was to plug the MGS Oil Pool and suspend this well for future evaluation of gas potential either through sidetrack or recompletion. AOGCC approved the sundry on July 16. On July 17 Hilcorp rigged up coil tubing on the Baker platform to mill through the debris in the tubing. Coil mill BHA made it through the obstruction at 8795’ and out the end of tubing at 9296’. An injectivity test was performed up to 2000 psi, and no injectivity was attained into the perforations. A reverse nozzle was used to RIH to the end of the coil reel at 10,686’ (top perf at 10,220’) and lay 27 bbls of 14 ppg cement across the perforations and into the tubing. Coil was picked up to 9040’ and circulated clean to ensure the sliding sleeve was clear. The well was then circulated with 9.8 ppg brine. On October 8 AOGCC witnessed slickline tag with a 2.5” bailer at 9345’ and a successful combo MIT to >2400 psi per the sundry (initial: 2598 psi, 15 min: 2551 psi, 30 min: 2529 psi). Service Wells MGS ST 17595 16 and MGS ST 17595 17 (Baker 16 and 17) 6 In accordance with AIO 7.004, Hilcorp performed successful MITs on both service wells prior to commencing disposal operations. Initial MITs were performed on May 15. Subsequent MITs were conducted on May 21. Below are tables of the volumes disposed of in each well through this season’s activity. Baker Platform Injection Well Report Well Ba-16 Date Time Fluid Type Fluid Source Tubing (LS) Pressure 9-5/8" Annulus Pressure 13-3/8" Annulus Pressure Rate BPM Total BBLS Total Vol Pumped 5/17/2024 7:30 FIW uprights 1950 0 170 3 100 100 5/18/2024 17:00 Brine/diesel Ba-23 1500 0 160 2.5 40 140 5/21/2024 7:30 FIW/oil Ba-25 1725 0 160 2.7 70 210 5/23/2024 15:00 Brine/diesel Ba-4/6/20 1650 45 160 2.7 180 390 5/25/2024 18:30 FIW/oil Ba-13 1800 40 160 3 55 445 6/4/2024 17:00 FIW/oil Ba-5 1500 0 170 2.5 55 500 6/6/2024 7:00 FIW/Brine Ba-5 Ba-29 1300 0 170 2.7 55 555 6/7/2024 14:00 FIW/oil Ba-11 1600 0 160 2.8 77 632 6/8/2024 6:30 FIW/oil Ba-28 1600 0 160 2.8 40 672 6/9/2024 15:30 FIW/oil Ba-30 1350 0 170 2.4 65 737 6/11/2024 17:30 FIW/oil Ba-30 1550 0 180 2.7 59 796 6/13/2024 11:30 FIW/oil Uprt/BA-30 600 0 180 1 36 832 6/29/2024 13:30 FIW Ba-25 1050 0 160 1.8 85 917 7/1/2024 17:00 FIW/oil Ba-5 Ba-13 1250 0 160 2.3 150 1067 7/3/2024 9:30 FIW Ba-5 1600 0 160 2.8 364 1431 7/5/2024 12:30 Brine/diesel Ba-23 1400 0 160 2.4 127 1558 7/19/2024 9:30 Brine/FIW Ba-31 800 0 160 1 81 1639 7/20/2024 9:30 FIW/oil Ba-31 900 0 160 1.5 237 1876 9/21/2024 11:00 FIW/Brine Ba-04 1450 0 160 2.6 333 2209 9/22/2024 17:00 FIW/Brine Ba-04 1600 0 160 2.7 130 2339 9/23/2024 6:00 FIW/Brine Ba-04 1700 0 160 2.8 191 2530 10/2/2024 7:30 FIW/Oil Ba-11 1400 0 160 1.4 263 2793 10/4/2024 8:00 FIW/Oil Ba-11/25 1550 0 160 2.75 359 3152 10/5/2024 11:00 FIW/Oil Ba-25 1450 0 160 2.5 207 3359 10/7/2024 18:30 FIW Ba-28 1400 0 160 2.6 255 3614 10/13/2024 14:45 FIW/Oil Ba-29/28 1450 0 160 2.7 361 3975 10/14/2024 1500 FIW/Oil Ba-28/29 1480 0 160 2.7 429 4404 7 Baker Platform Injection Well Report Well Ba-17 Date Time Fluid Type Fluid Source Tubing (LS) Pressure 9-5/8" Annulus Pressure 13-38" Annulus Pressure Rate BPM Total BBLS Total Vol Pumped 5/17/2024 11:00 FIW Upright 1900 140 170 4 100 100 100 6 1 Hilcorp Alaska, LLC Casey Morse Well Integrity Engineer 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 August 22, 2024 Bryan McLellan Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 VIA EMAIL Subject: Docket Number: OTH-22-005 2024 Cook Inlet Well P&A Plan Updates Dear Mr. McLellan, This letter is in reference to Other Order 193 and is in response to your email dated July 23, 2024 requesting information regarding the risk profile for non-producing platforms in Cook Inlet, and specifically seeking: 1. The risk profile for [Middle Ground Shoal] MGS “C” platform relative to Spurr and other Cook Inlet platforms, and 2. A subsurface description and cross section describing the significant hydrocarbon resources accessible from MGS “C”. Other Order 193 granted approval for Hilcorp’s request to reprioritize the P&A plans for wells on the Baker, Dillon, and Spurr platforms based on the findings of AOGCC hearing held on March 29, 2022. In that hearing, Hilcorp explained its rationale for risk ranking the P&A activity. Since that time, Hilcorp completed several projects to advance P&A activity in the Cook Inlet. Progress was detailed in Hilcorp's letters dated November 21, 2022 and November 10, 2023. AOGCC and Hilcorp held a meeting on November 28, 2023 to discuss progress and plans forward regarding the Cook Inlet P&A activities and Hilcorp’s proposed changes from the plans agreed to in Other Order 193. The topics discussed during the November 28, 2023 meeting were summarized in Hilcorp’s letter dated December 5, 2023. In this meeting, AOGCC Commissioners agreed that Hilcorp’s P&A progress to date was acceptable and Hilcorp’s plan to P&A the MGS “C” platform ahead of the Spurr was consistent with the evaluated risk associated with these platforms. In April of 2021, the gas pipeline running between MGS “A” platform and the MGS onshore facilities developed a leak. The remaining oil line which takes production from MGS “A” and “C” was converted to a fuel gas supply line to keep power online at the “A” and “C” platforms while Hilcorp evaluated the commercial viability of a pipeline repair. As a result of this pipeline failure and the pipeline configuration in Middle Ground Shoal, production from both platforms “A” and “C” had to be shut in at that time. Hilcorp concluded its evaluation in late 2021 and determined that the resource accessible by platform “A” could justify the pipeline repair in conjunction with other development projects or more favorable market conditions. In no scenario did it make commercial sense to return the MGS “C” platform to production based on the remaining resources accessible by its wells. As such, Hilcorp determined the wells on MGS “C” have no future utility. Hilcorp maintained gas supply to the “A” and “C” platforms throughout 2022 and into 2023 while it cleaned and purged vessels to reduce risk and prepare the platforms for “lighthouse” operation. In September of 2023, By Samantha Coldiron at 12:27 pm, Aug 22, 2024 2 gas supply was shut off, associated personnel were relocated, and both platforms were converted to “lighthoused” status. Other Order 193 focused on the three “lighthoused” platforms at that time, specifically prescribing an order of P&A operations for the Dillon, Baker, and Spurr platforms. As of September 2023, two additional platforms were converted to “lighthoused” status, and MGS “C” wells were evaluated as having no future utility. The wells on “C” were shut in at surface with reservoir perforations open to the wellbore. In contrast, the wells on Spurr all have subsurface isolation with confirmed mechanical integrity preventing potential flow or pressure from the reservoir to surface. These wells were all previously in Suspended status until AOGCC rejected Hilcorp’s request to extend their Suspended status in September of 2021. Hilcorp’s Cook Inlet Offshore facility structural integrity inspection program follows the guidelines of API RP 2SIM. The inspection frequency is determined considering variables such as Cook Inlet’s unique environment, results from pushover analyses, individual facility geometry (brace configuration, number of legs, etc.), damage and repair history, and the platform’s status as a manned or unmanned “lighthoused” facility. The inspection frequencies are reviewed and adjusted as needed annually based on the previous year’s inspection results. Inspections include the following: x Subsea Jacket Inspections x Splash Zone Leg Inspections x Cathodic Protection Surveys x Subsea Sonar Inspections x Topside Inspections Based on current findings, there is no identifiable risk differential between the integrity of the surface facilities at MGS “C” and Spurr Platforms; however, a holistic risk differential exists between these two “lighthoused” platforms because MGS “C” has wells open to the reservoir and Spurr does not. Hilcorp presented geologic interpretations of the Middle Ground Shoal Oil Pool and Gas Pool as defined in Conservation Order 44A to AOGCC Petroleum Engineering, Reservoir Engineering, and Geology staff on June 18, 2024 and July 9, 2024. Logs of all wells on MGS “C” are on file with the AOGCC. In conjunction with the publicly available production history and well intervention records, Hilcorp has determined that the remaining resources accessible from wells on MGS “C” do not support any commercial viability for returning the wells to production. Hilcorp has further determined none of the MGS “C” wells has remaining future utility. Sincerely, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC Phone: 1-907-777-8322 Email: Casey.Morse@Hilcorp.com Digitally signed by Casey Morse (11458) DN: cn=Casey Morse (11458) Date: 2024.08.22 10:19:43 - 08'00' Casey Morse (11458) 5 1 Hilcorp Alaska, LLC Casey Morse Well Integrity Engineer 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 December 5, 2023 Chairman Brett Huber, Sr. Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 VIA EMAIL AND CERTIFIED MAIL Subject: Docket Number: OTH-22-005 2023 Cook Inlet Well P&A Plan Updates Dear Chairman Huber, This letter is in reference to Other Order 193 and outlines changes in Hilcorp’s planned Plug and Abandonment activities in the Cook Inlet. Other Order 193 granted approval for Hilcorp’s request to reprioritize the P&A plans for wells on the Baker, Dillon, and Spurr platforms based on the findings of AOGCC hearing held on March 29, 2022. Since that time, Hilcorp completed several projects to advance P&A activity in the Cook Inlet. Progress was detailed in Hilcorp's letters dated November 21, 2022 and November 10, 2023. AOGCC and Hilcorp held a meeting on November 28, 2023 to discuss progress and plans forward regarding the Cook Inlet P&A activities. Hilcorp presented several items that are changes from the plans agreed to in Other Order 193. 1. In 2023, Hilcorp completed P&A activities on the Dillon platform and the Subsea Well CI-17589-1A. Additionally, Hilcorp executed several projects to prepare the Baker platform for P&A. Hilcorp plans to conduct subsurface diagnostic work on the Baker wells in Spring 2024 and progress wellbore abandonment work through the remainder of 2024 to isolate all open oil reservoir perforations. Hilcorp is conducting further evaluation of the utility of each of the 25 wells on the Baker platform to determine possible gas potential or use as sidetrack candidates for testing gas resources near the platform. All findings will be communicated through the sundry process via requests to either abandon wells or to convert certain wells to Suspended status following reservoir abandonment work. The Baker platform is visited at least once per month for wellbore pressure readings and facility inspections. There is power on the platform to maintain the corrosion control and lighthouse systems. 2. Based on further evaluation of the risk profile for Hilcorp’s assets in the Cook Inlet, Hilcorp proposes abandonment of the Middle Ground Shoal “C” platform follow the completion of the abandonment work on the Baker. Abandonment of the MGS “C” wells would therefore take place in 2025 per this plan. This is consistent with Hilcorp’s risk assessment approach of the Cook Inlet platforms as presented and discussed in the public hearing March 29, 2022. The MGS “C” platform is visited at least once per month for wellbore pressure readings and facility inspections. There is power on the platform to maintain the corrosion control and lighthouse systems. 2 3. Prioritizing the MGC “C” will further defer abandonment of the Spurr platform, which is now planned for 2026. All wells on the Spurr platform currently have reservoir abandonment plugs, and there are no current plans for utilizing these wellbores in the future. The Spurr platform is visited at least once per month for wellbore pressure readings and facility inspections. There is power on the platform to maintain the corrosion control and lighthouse systems. The above changes are consistent with Hilcorp’s approach to systematically mitigate risk in the Cook Inlet while preserving options for continued oil and gas development. Hilcorp looks forward to working with AOGCC on these projects and appreciates the collaborative approach towards risk mitigation and realizing further resource potential. Sincerely, Casey Morse Well Integrity Engineer Hilcorp Alaska, LLC Phone: 1-907-777-8322 Email: Casey.Morse@Hilcorp.com 4 1 Hilcorp Alaska, LLC Aras Worthington Senior Operations Engineer, PE 3800 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 November 10, 2023 Chairman Brett Huber, Sr. Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, Alaska 99501 VIA EMAIL AND CERTIFIED MAIL Subject: Docket Number: OTH-22-005 2023 Cook Inlet Well P&A Report Dear Chairman Huber, Please see the below summary of the 2023 Cook Inlet well plug and abandonment campaign. Hilcorp looks forward to meeting with the AOGCC no later than December 1 st, 2023, to discuss this report as required by Other Order 193. Sincerely, Aras Worthington Senior Operations Engineer, PE Hilcorp Alaska, LLC Phone: 1-907-564-4763 Mobile: 1-907-440-7692 Email: Aras.Worthington@Hilcorp.com Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643) Date: 2023.11.10 13:56:56 -09'00' Aras Worthington (4643) 2 Subsea Well CI-17589-1A P&A Although not a part of Cook Inlet platform well abandonments as Order 193 pertains to, the abandonment of subsea well CI-17589-1A was completed on July 11th, 2023. The completion of this abandonment was the culmination of a years-long effort to complete the P&A. Jack-up drilling rig Spartan 151 spent the first six weeks of the summer drilling season mobilizing to/from or working on this P&A in 2023. Similarly, Spartan 151 spent about one month working on the abandonment in 2021, although very little progress was made in 2021 other than to discover the manifold challenges in achieving pressure-control on the well prior to intervening in it. The interim years were spent devising a way to acquire precise measurements of the subsea wellhead, surveying the wellhead with LiDAR, and designing, manufacturing, testing and finally installing that pressure-containment system for well control during the P&A. 2023 Platform Well Abandonment Campaign Operations to prepare the Dillon platform for the continuation of the well P&A program began on April 15th, 2023. Start-up of the temporary camp (after the shut-down through the winter months) and re-installation all P&A ancillary facilities (tank farm, cement silos) took about one month. On May 16, 2023, the above was complete and P&A wellwork commenced. For the next six weeks Hilcorp finished P&A work on the nine remaining wells that had not been completed in 2022. On June 26, 2023, the last cement plug was pumped into well S MGS Unit 16, completing P&A of the wells on the platform. After removal of the trees and valves from the Dillon wells a site clearance inspection by AOGCC was completed on August 15, 2023. In the meantime, the temporary camp and P&A kit was moved to the Baker platform. The Baker platform required disassembly and relocation of the heliport to above the temporary camp to access all wells on the platform. This work, including disassembly of the strong-backs (I-beam support structures) on Dillon and reassembly on Baker took the project out until early November of 2023. At this point the camp was blown-down for the winter months to resume operations in the Spring of 2024. The Baker platform P&A is intended to P&A the oil-zones of the wells but salvage the upper portion of the completions for possible use as drilling sidetrack donor wellbores to access known gas reservoirs north of the Baker platform. This gas-development possibility is still being evaluated. Hilcorp intends to complete the remaining oil-zone reservoir abandonments on the Baker wells in 2024. Hilcorp proposes to execute the Platform C well P&As in 2025, rather than move to the relatively benign Spurr platform wells (all nine of the Spurr wells already have a cement reservoir abandonment plug in place). Spurr platform update: The crane is operational. Pipelines were abandoned in 2021. Normal annual integrity maintenance activities have been identified for remediation. There are no known integrity issues with the platform that preclude execution of the well P&As in 2026. 3 Lessons Learned: x Through-tubing abandonment methods and the manifold lessons learned (roughly 60 P&As on the North-Slope in the last dozen years performed with through-tubing methods) transferred very well to CIO wells x High-volume (large) cement plugs are a best-practice for through-tubing P&A. If displacements are affected by either scale or pitting it doesn’t materially affect the cement plug placement so long as the plug is large. x Coiled Tubing will continue to be required on wells that have tubing integrity issues to get reservoir cement plugs in place (five wells on Dillon required CT interventions to P&A). x A new cementing vendor local to Alaska performed very well on the 2023 Dillon campaign. x Acquiring circulating flanges for all annuli and tubing strings for the wells on the platform was a major time, labor, and efficiency improvement from 2022. These flanges are now part of the P&A kit Hilcorp will take to each platform P&A campaign. These are all installed once in the beginning of the project and are not removed until the last cement plug is pumped in each well. x Filtered Inlet water blended into a 14-ppg slurry is a reliable P&A cement and is effective for all the cement plugs required for P&A. x A dedicated brine mixing tank was refurbished for the 2023 campaign which increased efficiency and parallel operations while performing other wellwork. 4 Well-by-well discussion of Dillon P&As: S MGS Unit 02RD: Diesel freeze-protect was circulated out of the LS, SS, and IA. Two bottoms-up plus surfactant wash were circulated up the IA through the tubing punches @ 2125’ MD. The surface cement plug was pumped down the LS with returns from the IA. Good cement returns were observed from the IA at the appropriate volume pumped (159 bbls) and returns were swapped to the SS. Good cement returns were observed from the SS at the appropriate volume pumped (3 bbls). The OA had already been cemented to surface the previous year by OA downsqueeze. Good cement was observed at surface when the tree was ND in the LS, SS, IA, OA. The OOA TOC was tagged 2” below the outlet. The P&A is complete. 5 S MGS Unit 04: Diesel freeze-protect was circulated out of the LS, SS, and IA. A 1000’ intermediate balanced cement plug was pumped down the LS and into the IA and SS with 9.8 ppg brine above the cement plug. The cement plug was intended to extend from the perforations @ 2500’ MD up to ~1500’ MD in the IA and LS, and from ~2500’ MD to surface in the SS. The perforations were squeezed with 8 bbls of cement away with no pressure. The TOC was tagged in the LS @ 1300’ MD and a sample of cement was recovered. An MIT of the LS to 1500 psi passed. The SS was perforated @ 500’ MD in preparation for the surface cement plug. Circulation from the LS to the OOA was not established (OOA cemented to surface during well construction). Two bottoms-up plus surfactant wash were circulated up the OA and IA. The surface cement plug was pumped down the LS. Good cement returns were observed from the OA at the appropriate volume pumped (35 bbls) and returns were swapped to the IA. The IA surfaced cement immediately so returns were swapped a couple times from IA to OA and eventually the OA plugged off @ 500 psi. Pressure was increased on the LS to 600 psi and circulation was regained. 32 bbls of pre-wash were recovered from the OA as appropriate (the pre-wash expected ahead of cement in the IA and OA). Good cement returns were taken from the OA and IA a second time to verify cement to surface. Returns were shut-in from all but the OOA and the OOA was squeezed five times @ 500 psi with an additional 3 bbls of cement. Good cement was observed at surface when the tree was removed in the LS, IA, OA, and OOA. The SS TOC was tagged @ 139’ MD (approximately 60’ above mudline). The P&A is complete. 6 S MGS Unit 05: Diesel freeze-protect was circulated out of the LS, SS, IA, and OA. Two bottoms-up plus surfactant wash were circulated up the OA and IA. Circulation from the tubing to the OOA was not established (the OOA was cemented to surface during well construction). The surface cement plug was pumped down the LS through the perforations @ 400’ MD and up the OA. Good cement returns were observed from the OA at the appropriate volume pumped (31.5 bbls) and returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (25 bbls) and returns were swapped to the SS. Good cement returns were observed from the SS at the appropriate volume pumped (2 bbls). Returns were shut-in from all but the OOA and the OOA was squeezed for five minutes @ 500 psi with an additional 2 bbls of cement. Good cement was observed at surface when the tree was removed in the LS, SS, IA, and OA. The OOA TOC was tagged one foot below the outlet. The P&A is complete. 7 S MGS Unit 09RD: Diesel freeze-protect was circulated out of the tubing and IA. A 3200’ intermediate balanced cement plug was circulated down the tubing and into the IA with 9.8 ppg brine above the cement plug. This cement plug was intended to extend from the perforations @ 4700’ MD up to ~1500’ MD in the IA and tubing. The TOC was tagged in the tubing @ 1410’ MD and a sample of cement was recovered. An CMIT-TxIA to 2500 psi failed. The tubing was perforated @ 500’ MD in preparation for the surface cement plug. Circulation from the tubing to the OOA was not established (OOA cemented to surface during well construction). Circulation to the OA and IA was clean. Two bottoms-up plus surfactant wash were circulated up the OA and IA. The surface cement plug was pumped down the tubing through the perforations @ 500’ MD and up the OA. Good cement returns were observed from the OA at the appropriate volume pumped (44 bbls) and returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (37 bbls). Returns were shut-in from all but the OOA and the OOA was squeezed for five minutes @ 500 psi with an additional 0.9 bbls of cement. Good cement was observed at surface when the tree was removed in the tubing, IA, OA, and OOA. The P&A is complete. 8 S MGS Unit 11: Diesel freeze-protect was circulated out of the LS, SS, and IA. A 1500’ intermediate balanced cement plug was pumped down the SS and into the IA and LS with 9.8 ppg brine above the cement plug. This cement plug was intended to extend from the perforations @ 3000’ MD up to ~1000’ MD in the IA and SS, and from ~3000’ MD to surface in the LS. There was a loss of returns of into the perforations (>10 bbls) during the cement job so no squeeze was performed and the LS did not surface cement. The TOC was tagged in the SS @ 1048’ MD and a sample of cement was not recovered. The TOC was tagged in the LS @ 598’ MD and a sample of cement was recovered. A CMIT-LSxSSxIA to 2500 psi failed. The LS was perforated @ 500’ MD and while circulation was established to the IA and OA, it was not established to the SS. The SS was perforated @ 550’ MD to establish SS x LS circulation in preparation for the surface cement plug. Circulation from the LS to the OOA was not established (OOA cemented to surface during well construction). Two bottoms-up plus surfactant wash were circulated up the OA and IA. The surface cement plug was pumped down the SS. Good cement returns were observed from the OA at the appropriate volume pumped (45 bbls) and returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (31 bbls) and returns were swapped to the LS. Good cement returns were observed from the LS at the appropriate volume pumped (6 bbls). Returns were shut-in from all but the OOA and the OOA was squeezed for five minutes @ 500 psi with an additional 2.5 bbls of cement. Good cement was observed at surface when the tree was removed in the LS, IA, OA, and OOA. The TOC in the SS was tagged 2’ down from the tubing hanger. The P&A is complete. 9 S MGS Unit 13: The Tubing, 9-5/8”, and 13-3/8” casings were perforated @ ~400’ MD the previous Fall (2022) in preparation for the surface cement plug. Diesel freeze-protect was circulated out of the LS and IA, however circulation from the LS to SS could not be established through the perforations @ 400’ MD. The SS was punched @ 400’ MD to establish circulation to the LS in preparation for the surface cement plug. Circulation from the LS to the OOA was not established (OOA cemented to surface during well construction). Two bottoms-up plus surfactant wash were circulated up the OA and IA. The surface cement plug was pumped down the LS. Good cement returns were observed from the OA at the appropriate volume pumped (28 bbls) and returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (21 bbls) and returns were swapped to the LS. Good cement returns were observed from the LS at the appropriate volume pumped (4 bbls). Returns were shut-in from all but the OOA and the OOA was squeezed for five minutes @ 500 psi with an additional 2.5 bbls of cement. Good cement was observed at surface when the tree was removed in the LS, SS, IA, OA. The TOC in the OOA was tagged 8’ down from the outlet. The P&A is complete. 10 S MGS Unit 16: Diesel freeze-protect was circulated out of the LS, SS, and IA. A 1500’ intermediate cement plug was pumped down the SS and into the IA and LS. This cement plug was intended to extend from the perforations @ 4500’ MD up to ~3000’ MD in the IA and SS, and then from ~4500’ MD to surface in the LS. Cement was not surfaced up the LS, and a subsequent tag of TOC in the LS was @ ~400’ MD. The TOC was tagged in the SS @ 2839’ MD and a sample of cement was recovered. An MIT of the SS to 1500 psi passed. The SS was perforated @ 402’ MD in preparation for the surface cement plug. Circulation from the SS to the OOA was not established however injection into the perforations was established @ 0.3bpm/850 psi, validating that the perforations did penetrate the OOA and beyond to formation. Circulation to the OA and IA was clean. Two bottoms-up plus surfactant wash were circulated up the OA and IA. The surface cement plug was pumped down the SS and 10 bbls of cement were squeezed into the OOA. Good cement returns were observed from the OA at the appropriate volume pumped (26 bbls) and returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (20 bbls) and returns were swapped to the LS. Good cement returns were observed from the LS at the appropriate volume pumped (4 bbls). Returns were shut-in from all but the OOA and the OOA was squeezed up to 900 psi with an additional 43 bbls of cement but eventually the squeeze broke down injecting @ 1 bpm/500 psi with no cement returns to surface. Good cement was observed at surface the following day in the LS, SS, IA, and OA. The OOA TOC was tagged @20’ below the wellhead. A borescope was run into the OOA, but it appeared that the cable coiled up in the OOA because no cement was observed and 120’ of cable was RIH. Approval was granted by AOGCC to saw the wellhead off with a diamond wire saw to verify cement in the OOA. This was completed and good cement to the cut was observed in the LS, SS, and IA. The OA TOC was 12” down from the cut. The TOC in the OOA was tagged with steel conduit pipe @ 40’ below the cut-off. Fluid was pumped out of the OOA down to 27’ (approximately the limit of the suction a pump can apply with only atmospheric pressure pushing the fluid up the pipe). The OOA and OA were top-jobbed to surface with 6 bbls of cement. The P&A is complete. 11 S MGS Unit 17: The LS was punched @ 9000’ MD just above the production packer to enable circulation of cement into the IA. The SS was punched @ 9000’ MD to enable circulation of cement into the SS. Surfactant followed by 9.8 ppg brine was circulated down the LS and into the IA to leave 9.8 ppg brine between the reservoir cement plug and the surface cement plug. 9.8 ppg brine was also circulated up the SS for the same purpose. Cement was circulated down the LS with returns from the SS and IA to get cement down to the tubing punches. Cement was then bullheaded into the perfs (102 bbls) for the reservoir cement plug. Returns were routed from the IA and 189 bbls of cement were circulated into the IA. The IA was shut-in and returns were routed from the SS, with 35 bbls of cement circulated into the SS. The planned TOC in the LS, SS, and IA was 5000’ MD, for a cement plug ~4000’ in length above the production packer in the LS, SS, and IA. The TOC was tagged in the LS @ 4881’ MD and in the SS @ 5476’ MD and a sample of cement was recovered from both. A CMIT-LSxSSxIA to 2500 psi passed. The LS was perforated @ 700’ MD in preparation for the first stage surface cement plug. A circulation test from the LS x SS revealed a leak from the starting head. A welding job patched the starting head leak successfully. The known leak from the OA to the OOA was verified by circulating a dyed pill indicating the leak at ~15’ below the wellhead. Two bottoms-up plus surfactant wash were circulated down the LS and up the OA and IA. The first stage surface cement plug was pumped down the LS with returns from the OA. Good cement returns were observed from the OA at the appropriate volume pumped (56 bbls) and a flush was pumped down the OOA with returns from the OA to clear any cement blockage in the OOA at surface. Cement was lined up down the LS and returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (36 bbls) and a wiper ball was dropped and displaced with 5.5 bbls to leave the TOC in the LS @ ~600’ MD. The LS was perforated @ 400’ MD in preparation for the second stage surface cement job however circulation could not be established from the LS to the OOA or SS. The SS was perforated @ 400’ MD and circulation was established from the LS to the OOA and SS. Two bottoms-up plus surfactant wash were circulated down the LS and up the OOA. The second stage surface cement job was pumped down the LS with returns from the OOA. Good cement returns were observed from the OOA early @ 36 bbls away. Cement was circulated up the OOA until returns from OOA were 13.8 ppg (52 bbls away). Returns were swapped to the OA and good cement returns were observed at surface @ 4 bbls away. Good cement was observed at surface when the tree was removed in the SS, IA, OA, and OOA. The LS TOC was tagged @ 15’ below the tubing hanger. The P&A is complete. 12 S MGS Unit 18: The Tubing, 9-5/8”, and 13-3/8” casings were perforated @ ~410’ MD the previous Fall (2022) in preparation for the surface cement plug. Diesel freeze-protect was circulated out of the LS, SS, IA, OOA, and OA. Two bottoms-up plus surfactant wash were circulated up the OOA, OA and IA. The surface cement plug was pumped down the LS with returns from the OOA. Cement returns were observed early from the OOA (30 bbls away/ calculated 56 bbls away). Cement was continuously pumped with returns from the OOA until 120 bbls total away and 12.8ppg cement returns were observed from the OOA. Returns were swapped to the OA. 12.8 ppg cement returns were observed from the OA immediately so returns were swapped to the IA. Good cement returns were observed from the IA at the appropriate volume pumped (20 bbls). Returns were swapped to the SS and good cement returns were observed from the SS at the appropriate volume (4 bbls). Returns were shut-in from all but the OOA and the OOA was squeezed for five minutes @ 500 psi with no cement pumped away. Good cement was observed at surface when the tree was removed in the LS, SS, IA, OA, and OOA. The P&A is complete. 13 Dillon Platform Injection Well Report Well Di 17 MAXIMUM INJECTION PRESSURE IS 4600 PSI Date Time Fluid Type Fluid Source Tubing (LS) Pressure 9-5/8" Annulus Pressure 13-38" Annulus Pressure Rate BPM Total BBLS Total Vol Pumped 6/13/2022 3:00 inlet water Test 3600-2680 2000-2250 0 1.5 100 100 6/20/2022 15:00 Diesel DI 04 2927 2000 0 1 4.2 104.2 6/20/2022 15:00 Diesel DI 06 2927 2000 0 1 7.5 111.7 6/20/2022 15:00 Diesel DI 07 2927 2000 0 1 5.7 117.4 6/20/2022 15:00 Diesel DI 08 2927 2000 0 1 5 122.4 6/20/2022 15:00 Brine DI 08 2927 2000 0 1 9 131.4 6/20/2022 15:00 Brine Di-11 2927 2000 0 1 7 138.4 6/20/2022 15:00 Diesel Di-11 2927 2000 0 1 4.5 142.9 6/20/2022 15:00 Diesel DI-16 2927 2000 0 1 4.6 147.5 6/20/2022 15:00 Diesel Di-17 2927 2000 0 1 8 155.5 6/20/2022 15:00 Brine Di-17 2927 2000 0 1 3.3 158.8 6/20/2022 15:00 Diesel Di-18 2927 2000 0 1 5 163.8 7/3/2022 17:30 Diesel DI-02 2918 2200 40 1.4 4.2 168 7/3/2022 18:00 Crude DI-03 2918 2200 40 1.4 24 192 7/3/2022 18:00 Diesel DI-03 3018 2100 53 1.4 15 207 7/3/2022 18:00 Diesel DI-04 2710 2060 75 1.4 14.5 221.5 7/3/2022 18:00 Brine DI-05 2730 2210 75 1.4 11 232.5 7/3/2022 19:00 Crude DI-05 2690 2025 68 1.5 5 237.5 7/3/2022 19:00 Diesel DI-05 2775 2220 65 1.5 15 252.5 7/3/2022 19:00 Diesel DI-09 2990 2215 62 1.5 5.4 257.9 7/3/2022 19:45 Brine Di-12 3090 2210 60 1.5 38.8 296.7 7/14/2022 8:00 Diesel Di-18 2150 2250 0 1 15 311.7 7/14/2022 8:00 Brine Di-18 2150 2250 0 1 70 381.7 8/3/2022 14:00 Brine DI-14 2630 2250 60 1.25 68 449.7 8/3/2022 21:00 Brine DI-14 2760 2250 60 1.25 63 512.7 8/4/2022 7:00 Brine DI-14 3450 2250 60 2.7 167 679.7 8/4/2022 7:00 Crude DI-03 3430 2250 60 2.5 30 709.7 8/4/2022 19:00 Brine DI-14 2840 2200 60 2.5 110 819.7 8/5/2022 15:00 Brine Di-14 3060 2200 60 2.7 197 1016.7 8/7/2022 13:30 Brine Di-06 3000 2200 60 2.7 115 1131.7 8/13/2022 14:30 Brine DI-07 2300 2250 60 3.5 220 1351.7 8/13/2022 10:30 Brine DI-07 2500 2250 50 3.5 315 1666.7 8/13/2022 22:00 Brine DI-07 2800 2250 60 3.5 50 1716.7 8/14/2022 10:30 Brine DI-12 2500 2250 60 3.5 136 1852.7 8/15/2022 10:30 Brine DI-12 2350 2250 50 3.5 781 2633.7 8/16/2022 14:45 Brine/Crude DI-13 2630 2250 40 3.5 93 2726.7 8/18/2022 13:00 Brine DI-12 2600 2250 40 3.5 725 3451.7 8/19/2022 13:30 Brine DI-3 2650 2250 40 3.5 200 3651.7 8/21/2022 06;30 Brine/Diesel DI-3 2700 2250 0 3.5 702 4353.7 8/24/2022 11:00 Brine/Diesel DI-18 2900 2250 0 3.5 402 4755.7 8/24/2022 16:30 Brine DI-18 3000 2250 0 3.7 255 5010.7 8/26/2022 9:30 Brine/Crude Di-8 3000 2250 0 3.5 336 5346.7 9/2/2022 10:30 Brine/Diesel Di-8 3000 2100 0 3.2 351 5697.7 9/3/2022 17:30 Brine/Diesel Di-4 2700 2100 0 3 175 5872.7 9/5/2022 8:00 Brine/Diesel Di-15 2750 2200 0 3 615 6487.7 9/17/2022 12:00 Brine/Diesel DI - 10 2500 2200 0 2.5 160 6647.7 9/19/2022 13:00 Brine/Diesel DI 14 2650 2250 0 2.5 260 6907.7 9/22/2022 7:00 Brine Di-12 2500 2200 50 1.7 168 7075.7 9/22/2022 9:00 Brine Di-03 2550 2200 50 1.8 223 7298.7 9/22/2022 12:30 Crude/Diesel Di-03 2400 2200 45 2 34 7332.7 9/27/2022 7:00 Brine Di-15 2500 2250 50 2 164 7496.7 9/29/2022 17:00 Brine Di-06 2650 2225 50 2.1 253 7749.7 9/29/2022 19:00 Brine Di-11 2650 2225 50 2.1 57 7806.7 9/30/2022 17:00 Brine Di-11 2600 2225 55 2.3 299 8105.7 10/3/2022 6:30 Brine Di-11 2500 2250 60 1.5 230 8335.7 10/3/2022 17:00 Brine Di-11 2500 2225 60 1.5 358 8693.7 10/13/2022 14:30 Brine/ oil DI -11 2550 2250 60 1.4 289 8982.7 10/15/2022 0:00 Brine/ oil DI-18 2550 2250 60 1.4 178 9160.7 10/21/2022 20:00 Brine Di-09 2500 2200 60 1.4 321 9481.7 10/22/2022 4:30 Brine Di-11 2670 2250 60 1.4 207 9688.7 10/27/2022 9:00 Brine Di-09 2580 2225 55 1.4 85 9773.7 10/30/2022 8:00 Brine Di-05 2570 2200 55 1.4 72 9845.7 11/1/2022 7:00 Brine/Oil Di-16,Di-05 2500 2250 50 1.4 468 10313.7 11/2/2022 9:00 Brine/Oil Di-16 2500 2200 50 1.4 172 10485.7 11/3/2022 13:00 Brine/Oil Di-16 2550 2250 50 1.4 234 10719.7 11/6/2022 15:00 Brine Di-16 2500 2250 50 1.5 162 10881.7 14 Dillon Platform Injection Well Report Well Di 17 MAXIMUM INJECTION PRESSURE IS 4600 PSI Date Time Fluid Type Fluid Source Tubing (LS) Pressure 9-5/8" Annulus Pressure 13-38" Annulus Pressure Rate BPM Total BBLS Total Vol Pumped 5/15/2023 0:00 FIW RRtank 2000 2000 120 1.4 222 11104 5/19/2023 0:00 Brine/Diesel D1-16 2200 2000 0 1.4 249 11353 5/21/2023 0:00 Brine/Diesel DI-11 2100 2100 0 1.4 201 11554 5/23/2023 0:00 Brine/Diesel DI-4 2100 2200 0 1.4 109 11663 5/25/2023 0:00 Brine/Diesel DI-9 2100 2200 0 1.4 260 11923 5/26/2023 0:00 Brine/Diesel DI-2 2100 2200 0 1.4 182 12105 6/4/2023 0:00 Brine/Diesel Di04/Di13 2600 2050 0 2 244 12349 6/6/2023 0:00 Brine/Diesel Di-09 2700 2100 0 1.8 241 12590 6/8/2023 13:00 Brine/Diesel Di-11 2500 2200 0 2.3 256 12846 6/11/2023 16:30 Brine/Diesel Di-16/Di-18 2750 2200 0 3 486 13332 Hilcorp Alaska, LLC Aras Worthington Senior Technical Advisor for Alaska Operations 3500 Centerpoint Dr., Suite 1400 Anchorage, Alaska 99503 November 21, 2022 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7`^ Avenue Anchorage, Alaska 99501 VIA EMAIL AND CERTIFIED MAIL Subject: Docket Number: OTH-22-005 2022 Dillon Platform Well P&A Report Dear Commissioner Chmielowski, il-iC.EIVE® NOV 2 3 2022 AOGCC Please see the below summary of the 2022 Dillon platform well plug and abandonment. Hilcorp looks forward to meeting to meeting with the AOGCC no later than December 1", 2022, to discuss this report as required by Other Order 193. Sincerely, Aras Worthington (4643) Digitally signed by Aras Worthington (4643) DN: cn=Arcs Worthington (4643), ou=Users Date: 2022.11.21 13:53:14 -09,00, Aras Worthington Senior Technical Advisor for Alaska Operations, PE Hilcorp Alaska, LLC Phone: 1-907-564-4763 Mobile: 1-907-440-7692 Email: Aras.Worthington@Hilcorp.com Operations to prepare the Dillon platform for well P&A began on April 41", 2022. Clearing the drill -deck of stored and ancillary equipment was the first step, followed by installation of the temporary camp and all associated facilities to accommodate the well P&A team through the summer months. By June 1, 2022, all of the above was complete and diagnostic wellwork commenced. For the next seven weeks Hilcorp performed diagnostic work on all the subject wells in preparation for finalizing P&A plans. This included: 1. Drifting all tubing strings and fishing of toolstrings LIH from previous operator 2. Setting plugs in all tubing strings and pressure -testing or otherwise validating tubing integrity sufficiently to validate weather fullbore P&A methods could be pursued or coiled tubing was needed 3. Injectivity/pressure tests of all annuli 4. Acoustic and temperature E-line logs to verify leak depths in tubing and casing 5. Pumping of dyed pills to verify leak depths 6. Strapping of TOC (Top -of -Cement) in the OOAs of all wells 7. MITIA and injectivity test on the disposal well (well #17) to prepare it for Class 11 disposal operations throughout the P&A campaign As diagnostic work was performed, P&A sundries were drafted and submitted to AOGCC. Lessons Learned from the diagnostic work included the following: 1. In wells with scale evident in the tubulars the risk of losing a plug due to getting stuck in scale is high (three such plugs were lost in this campaign, two were recovered). a. Use of an E-line conveyed temperature tool is a good alternative to a plug and pressure -test to validate that fluid is conducted to the bottom of the tubing string and therefore cement will as well b. Use of a SL conveyed stranded -line tool to validate that fluid is exiting the tubing string at tubing punches is also a good alternative to a plug and pressure -test 2. To locate casing leaks E-line conveyed temperature and/or acoustic tool are an option, but for very shallow leaks dyed -pills circulated down one annulus and out another are also very clean indicators of the approximate depth of the leak. Both methods were used and validated on the 2022 campaign. Following the diagnostic work campaign, I-beam strong -backs were installed on the platform to support and distribute the weight of cement silos, return tank farms, cementing equipment, and CT equipment. A cement delivery system was installed to blow cement from bulk tanks on the workboats and up to the storage silos on the platform. This system was unfortunately never used due to boat limitations. The delivery of all cement for the project (roughly 2MM-Ibs of dry cement product) was in the end via cement pods and crane. This was extremely labor intensive as the pods had to be loaded on land, craned on to the boat, craned off the boat, blown down, then re -loaded on the boat. Punching tubing strings for cement circulation and cement plug installation began in late July. Due to the strain on the fleet of Kenai -based wellwork equipment and vendors (particularly cementing equipment) the cementing equipment and crews had to be de -mobilized from the platform several times to cover new -drill cement jobs on land and offshore. This resulted in inefficiencies and delays of cement jobs on the Dillon, but good progress of the P&A project was still realized. Pressure -tests of cement plugs became a particular challenge. AOGCC interprets 25.112 (g) (2) "testing of the plug to hold a surface pressure..." to mean that the cement plug and the casing above it must pass a 30-minute "MIT" with equivalent pass/fail criteria to an active injection well. While this may appear to be a duly stringent criteria it is problematic on wells that may never have had an MIT of any kind, other than a casing test during well construction ca. late 1960s. Several wells did not pass these criteria on the first or second witnessed test, even though Hilcorp tried many times to pressure -test them before and between witnessed pressure -tests to get them to pass the stringent criteria. This caused inefficiencies for both Hilcorp and AOGCC in progressing the P&As. In an effort to extend the working season on the platform and complete the P&A project in 2022, Hilcorp winterized the temporary camp and the wellwork kit including installing heat traces on plumbing and installing jet heaters in the well - legs. This effort extended the season a few weeks but not long enough to complete all the P&As. On November 3, 2022, the last cement job of the 2022 campaign was pumped with considerable difficulty in starting equipment, clearing lines of ice prior to the cement job, and general winter weather effects. This was the 16" reservoir plug out of the 17 Dillon wells to install but after the job it was decided to wrap up the campaign and resume in the Spring of 2023 in more favorable (warmer) weather conditions. Final preparations for the winter months were completed that week including perforating and punching tubing for freeze -protection operations. The 2022 Dillon well P&A campaign results are as follows: ➢ 8/17 wells P&A completed ➢ 16/17 reservoir P&A completed (TA'd) ➢ 26 cement plugs pumped ➢ 13 cement plugs left to pump (mostly smaller surface plugs; only one big reservoir plug left to pump is on 17 — the disposal injector we use) ➢ 8 pert jobs left ➢ 5 witnessed MITs left Lessons Learned from the P&A work completed include the following: 1. Cement delivery needs to be better planned. The bulk cement delivery system we designed did not work due to unexpected boat limitations. We may need to plan for night crane ops to support Baker work with cement delivery via pods. 2. 14 ppg cement blend mixed in FIW worked well. 3. Consider and propose use of mud as completion fluid between cement plugs. Industry guidance indicates that mud will plug casing leaks and result in a higher likelihood of passing pressure tests of cement plugs/casing. 4. If mud is not an acceptable completion/weighted fluid, consider using CaC12 instead of NaCl/KCI to mix 9.8 ppg brine. CaC12 is easier to mix to 9.8 ppg and provides freeze -protection characteristics that NaCl and KCI do not. 5. Have a dedicated mixing tank on the platform from the beginning of the campaign as part of the tank farm. The 2022 campaign did not complete the Dillon work as Hilcorp planned. Hilcorp plans to complete all the Dillon well P&As in 2023 and then start on the Baker platform well P&As. With better efficiency and lessons learned in -hand Hilcorp endeavors to complete both the Dillon and Baker well P&A work next year but it is unlikely that Baker platform P&As will be completed in 2023. Hilcorp proposes to re -visit any needed changes to the schedule of P&A completions at the end of the 2023 P&A work season. Spurr platform update: The crane is operational. Pipelines were abandoned in 2021. Normal annual integrity maintenance activities have been identified for remediation. There are no known integrity issues with the platform that preclude execution of the well P&As in 2024. Well -by -well discussion of Dillon P& As: S MGS Unit 02RD: Pre-P&A diagnostics revealed that the OA had injectivity (the only Dillon well with injectivity into either the OOA or the OA). As well, the OA would repressurize to —230 psi in less than a day when bled down. For these reasons the P&A was planned to cement the OA fully via OA cement down -squeeze. This operation went as planned and the OA was successfully fully cemented and squeezed to —100 psi. Monitoring of the OA after the cement job showed that there was no re -pressurization and the OA stayed at 0 psi during the P&A campaign and there is cement -to -surface in the CA. The OOA TOC was tagged "4" below the outlet and was PT'd to 500 psi with no injectivity. The LSxSSxIA was successfully PT'd to 500 psi. The reservoir was plugged with LCM and fibers ca. 2011 by the previous operator. A variance to leave this plug in place was requested and approved by AOGCC in the P&A Sundry application. The production tubing is known to have multiple holes from ^2500' — 6500' MD. The P&A plan was to have Coiled Tubing install the lower cement plug via a cement retainer set near the production packer. This was done and —3000' of cement was placed in the tubing and IA as a balanced plug. The TOC in the tubing was tagged @ ^5233' SLM. The planned TOC was —5600' MD. The first AOGCC witnessed CMIT of the TxIA was deemed inconclusive. Hilcorp performed several MITs on the well after the first test and called out for a second witnessed CMIT. This was also deemed inconclusive, however Jim Regg later indicated that it would be considered a passing CMIT. A CIBP was set in the tubing @ —2150' MD per the approved Sundry and the LS was punched @ 2125' MD in preparation for the TxIA surface cement plug. Winter weather conditions prevailed and the TxIA was freeze -protected with diesel to —120' MD for the winter. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 03: The reservoir was plugged with LCM and fibers ca. 2011 by the previous operator. A variance to leave this plug in place was requested and approved by AOGCC in the P&A Sundry application. The production tubing LS and SS were verified to have integrity with a plug set in each @ —9150' SLIM and PT'd to 500 psi. The LSxSSxIA was successfully PT'd to 500 psi. The OA and OOA had no injectivity @ 500 psi. The OOA TOC was tagged @ "'1" below the outlet. The lower cement plug was planned to be —6300' in length and circulated down the LS of tubing and up the IA and S5, balanced in all strings and annuli. This cement plug was pumped as planned with no issues. The TOC in the LS was tagged @ 3750' SLM and in the SS @ 3233' SLM (planned TOC was —3000' MD). The first AOGCC witnessed CMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later passed upon engineering review. The LS, SS, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Cement was pumped per plan with good cement returns from the OA, IA, and SS. The OOA was squeeze to 500 psi with no circulation or returns to surface from the OOA. This P&A is complete. 4 S MGS Unit 04: The reservoir was plugged with LCM and fibers ca. 2011 by the previous operator. A variance to leave this plug in place was requested and approved by AOGCC in the P&A Sundry application. The production tubing LS and SS were verified to have integrity with a plug set in each @ 8597' SLM and 8502' SLM respectively, and PT'd to 500 psi. The CA and OOA had no injectivity @ 500 psi. The ODA TOC was observed at surface through the outlet gate valve. The LSxSSxIA was successfully PT'd to 500 psi. The lower cement plug was planned to be `5700' in length and circulated down the LS of tubing and up the IA and SS, balanced in all strings and annuli. This cement plug was pumped as planned with no issues. The TOC in the LS was tagged @ 2629' SLM and in the SS @ 2763' SLM (planned TOC was —3000' MD). The first AOGCC witnessed OMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later deemed a fail upon engineering review. Two revised Sundry applications were filed for this well for continuation of the P&A: the first with perforations near the SC (13-3/8") shoe and would fill almost all of the CA with cement. Discussions with AOGCC staff indicated that a passing MIT would need to be achieved before pumping the surface cement plug, so a second revision was submitted that included perforating @ —2500'and pumping a —1000' cement plug in the TxIA. This plug would be tagged and MIT'd, then the LS, SS, 9-5/8", and 13-3/8" casings perforated @ —500' MD for the surface cement plug. Hilcorp is awaiting approval on either of these P&A proposals to proceed. The LS, SS, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Cement was pumped per plan with good cement returns from the CA, IA, and SS. The ODA was squeeze to 500 psi with no circulation or returns to surface from the ODA. Winter weather conditions prevailed and the AOGCC granted permission to perforate @ —2500' MD for freeze - protection purposes. The TAA was freeze -protected with diesel to —120' MD for the winter. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 05: The reservoir was plugged with packer by the previous operator during a rig workover. A variance to leave this plug in place was requested and approved by AOGCC in the P&A Sundry application. The production tubing LS was verified to have integrity with a plug set @ 5000' SLM and PT'd to 500 psi. The CA and OOA had no injectivity @ 500 psi. The ODA TOC was tagged @ —1" below the outlet. The LSxSSxIA was successfully PT'd to 2500 psi. The lower cement plug was planned to be —3400' in length and laid in with coiled tubing. This cement plug was pumped as planned with no issues. The TOC was tagged @ 5818' SLM in the 9-5/8" casing (planned TOC was —6300' MD). The first AOGCC witnessed OMIT of the TAA was a pass. A CIBP was set in the tubing @ —500' MD per the approved Sundry and the 9-5/8" and 13-3/8" casing were perforated @ 400' MD in preparation for the TXIAxOAx00A surface cement plug. Circulation was established across all but the ODA. Winter weather conditions prevailed and the TxIAxOA was freeze -protected with diesel to —120' MD for the winter. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 06: The reservoir was plugged with a series of cement retainers and cement with the last plugging performed ca. 2011 by the previous operator. The production tubing was verified to have integrity with a plug set @ —1700' SLM and PT'd to 500 psi. The TxIA was successfully PT'd to 500 psi however they communicated through very shallow 9-5/8" and 13-3/8" casing leaks to the CA and ODA. Commensurately, the CA and ODA had no injectivity @ 500 psi. The casing leaks were both found to be @ —34' MD (at the wellhead) using temperature and acoustic logs. The ODA TOC was tagged @ —22' below the outlet. The first cement plug was planned to cement the IA from the tubing tail @ —1800' MD to above the mudline, circulated down the tubing and up the IA. This cement plug was pumped as planned with no issues and the cement in the tubing displaced to an expected depth of —600' MD. The TOC in the tubing was tagged @ 250' SLM and bailed down to —288' SLM where hard cement was found. A revision to the Sundry application was submitted and a coiled tubing unit was rigged up to mill cement in the tubing down to the planned perforation depth. This was achieved and coiled tubing stacked 1OK-Ibs of weight down on the milled TOC @ 450' CTM. A bond log was performed on the tubing to verify the TOC in the IA was no more than 30' below the mudline per the revised sundry. The TOC in the IA was indicated @ ^36' above the mudline. Perforations were shot @ —400' MD for the CIA surface cement plug. Cement was circulated down the tubing, through the perforations, up the CA and to surface as per plan with good cement returns to surface. This P&A is complete. S MGS Unit 07: The reservoir was plugged with a packer by the previous operator. A variance to leave this plug in place was requested and approved by AOGCC in the P&A Sundry application. The production tubing was verified to have integrity with a plug set @'"9500' SLM and PT'd to 500 psi. The TxIA was successfully PT'd to 500 psi. The CA and ODA had very low injectivity @ 500 psi. The OOA TOC was tagged @ —1" below the outlet. The lower cement plug was planned to be —6600' in length and circulated down the tubing and up the IA, balanced in tubing and IA. This cement plug was pumped as planned with no issues. The TOC in the was tagged in the tubing @ 3527' SLM (planned TOC was ^3000' MD). The first AOGCC witnessed CMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later passed upon engineering review. The Tubing, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Cement was pumped down the CA and IA with good cement returns from the tubing. Cement to surface was also verified from the CA and IA. Cement return volumes matched with the excess cement pumped. The ODA was squeezed to 500 psi with no circulation or returns to surface from the ODA. This P&A is complete 0 S MGS Unit 08RD: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing was verified to have integrity with a plug set @ —8000' SLM and PT'd to 1000 psi. The plug was lost when POOH and the Tubing was further verified to have integrity via a temperature log which indicated flow while pumping below 9400' ELM and finally a stranded hole -finder which stopped @ 9750' SLM (at the tubing punches). The OA PT'd to 500 psi. The ODA had very low injectivity @ 500 psi. The ODA TOC was tagged @ -'2" below the outlet. The lower cement plug was planned to be —6700' in length and circulated down the tubing and up the IA, balanced in tubing and IA. This cement plug was pumped as planned with no issues. The TOC was tagged in the LS of tubing @ 3637' SLM. The TOC in the IA was tagged @ 3257' SLM (planned TOC was —3000' MD). The first AOGCC witnessed CMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later passed upon engineering review. The Tubing, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Cement was pumped down the CA and IA with good cement returns from the tubing. Cement to surface was also verified from the CA and IA. Cement return volumes matched with the excess cement pumped. The ODA was squeezed to 500 psi with no circulation or returns to surface from the ODA. This P&A is complete. S MGS Unit 09RD: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing was punched in two places by the previous operator when the deeper tubing punches plugged off. The tubing was verified to have integrity down to 6400' MD with a plug set @ —6400' SLM and PT'd to 1000 psi. The CA PT'd to 500 psi. The ODA had no injectivity @ 500 psi. The ODA TOC was observed at surface (at the outlet). The P&A plan was to have Coiled Tubing install the lower cement plug via a cement retainer set near the production packer. The tubing was punched @ —9911' MD just above where SL tagged fill in the tubing. A Coiled Tubing Unit was rigged up, drifted the tubing with a nozzle and set a retainer @ —9800' MD. Cement was pumped through the retainer into the IA and then laid in the tubing on top of the retainer for a total of `4900' of cement placed in the tubing and IA as a balanced plug. The TOC in the tubing was tagged @ "'5110' SLM. The planned TOC was —5000' MD. The first AOGCC witnessed CMIT of the TxIA was deemed a fail. Hilcorp performed several MITs on the well after the first test and called out for a second witnessed CMIT. This was also deemed a fail. A revised Sundry was submitted to AOGCC to install another deep cement plug above the first and then MIT and tag the second cement plug before installing the surface cement plug. The revision was approved and the tubing was punched @ —4700' MD in preparation for the second TxIA cement plug. Winter weather conditions prevailed and the TxIA was freeze -protected with diesel to `120' MD for the winter. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 10: The well was drilled to —2466' by a previous operator and cased with 13-3/8" casing to —2020' MD. The operations reportedly encountered directional difficulties and the well was abandoned with a cement plug placed across the surface casing shoe. The well was left with Kill Weight Fluid in the casing above the cement plug with no tubing installed and no pressure containment equipment on the 13-3/8" casing. The OOA TOC was tagged @ —2.5" below the outlet. The surface cement plug was planned to be —400' in length and circulated in with a sacrificial killstring. This cement plug was pumped as planned with no issues. The TOC was witnessed at surface by the AOGCC inspector. This P&A is complete. 5 MGS Unit 12: The production tubing strings (LS & SS) had significant scale and multiple Left -In -Hole (LIH) EL and SL toolstrings. Hilcorp fished the toolstrings from the SS with SL and Coiled Tubing and milled/cleaned out the scale from the SS down to the production packer. This took considerable effort and several weeks of SL interventions as well as about a week of Coiled Tubing work. When fishing was completed injectivity into the well was at first established at less then 1 bpm, but later the perforations plugged off and injectivity was lost. An attempt to set a plug in the SS just above the packer was unsuccessful and the tools became stuck (suspect the SS is split at the bottom). An EL temperature log was performed pumping down the SS with returns from the IA verifying circulation to just above the production packer. The SS was perforated just above the production packer and into the LS. Circulation was established down the SS, up the LS, and up the IA through the perforations. A variance to place the deep cement plug just above the production packer was approved by AOGCC in the P&A Sundry application. The CIA and OOA were PT'd to 500 psi with no injecitivity. The OOA TOC was strapped at —30' below the outlet. The lower cement plug was planned to be "'2000' in length and circulated down the tubing SS and up the IA and LS, balanced in all tubing strings and IA. This cement plug was pumped as planned with no issues. The TOC in the tubing SS was tagged @ 6718' SLM. The planned TOC was —7000' MD. The AOGCC witnessed OMIT of the LSxSS passed. The tubing SS was perforated @ —3000' MD in preparation for the second TxIA cement plug. Winter weather conditions prevailed and the TxIA was freeze -protected with diesel to —120' MD. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 12: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing LS was verified to have integrity with a plug set @ 4960' SUM and PT'd to 1000 psi. The plug was set deeper @ 9900' SUM but the pressure fall -off at this depth was —1 psi/sec. Several plug sets verified a small leak in the LS between 5100' and 5200' SUM but the bulk of the circulation down the tubing was apparently going through the punches deeper than 9900' MD. The tubing SS was verified to have integrity with a plug set @ 9000' SUM and PT'd to 1000 psi. The LSxSSxIA was PT'd to 500 psi with no injectivity. The CA was PT'd to 500 psi and verified to have no injectivity. There is no OOA on this well. The lower cement plug was planned to be —6000' in length and circulated down the LS tubing and up the IA and SS, balanced in tubing strings and IA. This cement plug was pumped as planned with no issues. The TOC was tagged in the LS of tubing @ 4213' SUM and in the SS of tubing @ 4160' SLM. The planned TOC was —4000' MD. The first AOGCC witnessed CMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later passed upon engineering review. The Tubing, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cementjob. Cement was pumped down the LS and out the IA, CIA, and SS with good cement returns from all annuli and tubing. This P&A is complete S MGS Unit 13: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing LS was verified to have integrity with a plug set @ 9100' SLM and PT'd to 1000 psi. The tubing SS was verified to have integrity with a plug set @ 9100' SLM and PT'd to 1000 psi. The LSxSSxIA was PT'd to 500 psi with no injectivity. The CA and ODA were PT'd to 500 psi and verified to have no injectivity. The OOA TOC was strapped @ 7" below the outlet. The lower cement plug was planned to be —5300' in length and circulated down the LS tubing and up the IA and SS, balanced in tubing strings and IA. This cement plug was pumped as planned with no issues. The TOC was tagged in the LS of tubing @ 4233' SLM and in the SS of tubing @ 3777' SLM. The planned TOC was —4000' MD. The first AOGCC witnessed CMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later passed upon engineering review, however this passing indication was later rescinded by AOGCC. Unfortunately, we had already perforated for the surface cement plug after we received the first indication that the MIT was considered passing. The precludes the MIT from being repeated. The Tubing, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Winter weather conditions prevailed and the TxlAxOA was freeze -protected with diesel to —120' MD. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 14: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing LS was verified to have integrity with a plug set @ 9300' SLM and PT'd to 1000 psi. The tubing SS is only one joint of tubing (35' MD deep). The LSxSSxIA was PT'd to 500 psi with low injectivity into the IA (presumably a casing leak). The OA and OOA were PT'd to 500 psi and verified to have no injectivity. The lower cement plug was planned to be —6450' in length and circulated down the LS tubing and up the IA, balanced in tubing string and IA. This cement plug was pumped as planned with no issues. The TOC was tagged in the LS of tubing @ 3722' SLM. The planned TOC was —3000' MO. The AOGCC witnessed CMIT of the TxIA passed. The Tubing, 9-5/8", and 13-3/8" casings were perforated @ `400' MD in preparation for the surface cementjob. Cement was pumped down the LS and out the IA, CA, and SS with good cement returns from all annuli and tubing. The OOA was squeezed to 550 psi with no cement squeezed away. This P&A is complete S MGS Unit 15: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing LS was verified to have integrity with a plug set @ 11,970' SLM and PT'd to 1000 psi. The tubing SS is only one joint of tubing (30' MD deep). The LSxSSxIA was PT'd to 500 psi and verified to have no injectivity. The OA and OOA were PT'd to 500 psi and verified to have no injectivity. The lower cement plug was planned to be —4970' in length and circulated down the LS tubing and up the IA, balanced in tubing string and IA. This cement plug was pumped as planned with no issues. The TOC was tagged in the LS of tubing @ 6998' SLM. The planned TOC was —7000' MD. The first AOGCC witnessed CMIT of the TxIA was deemed a fail by the Inspector. A second witnessed CMIT was deemed inconclusive but later passed upon engineering review. The Tubing, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Cement was pumped down the LS and out the IA, CIA, and SS with good cement returns from all annuli and tubing. The OOA was squeezed to 500 psi with no cement squeezed away. This P&A is complete 10 S MGS Unit 16: The reservoir perforations had injectivity and this well was held in reserve as a backup option for Class II disposal if the primary disposal well (SMGS Unit 17) developed issues, which it did not. The reservoir cement plug was the last cement job pumped in the 2022 season. The production tubing LS and SS were verified to have integrity with via an injectivity test into the perforations down the LSxSS to 2680 psi @ 1.25 bpm which showed no pressure communication to the IA. The tubing SS was punched @ 9770' MD in preparation for the lower (reservoir and TxIA). The CIA and ODA were PT'd to 500 psi and verified to have no injectivity. The lower cement plug was planned to be -5700' in length. Initially bullheaded down the SS tubing and into the perforations, then circulated and up the IA and LS, balanced in tubing strings and IA. This cement plug was pumped as planned with no issues. 25 bbls of cement were bullheaded into the perfs, then circulation up the IA and LS commenced. In all -40 bbls were injected into the formation (including losses while circulating cement up the IA and LS. The TOC was tagged in the SS of tubing @ 5570' SLM. The planned TOC was -5000' MD. The first AOGCC witnessed CMIT of the TAA was deemed a fail by the Inspector. A request to perforate @ -4500' MD was approved by AOGCC to circulate in freeze -protection and then possibly install a second cement plug to MIT and tag. The tubing SS, LS, and 9-5/8" casings were perforated @ -4500' MD. Winter weather conditions prevailed and the TxIA was freeze -protected with diesel to -120' MD. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. S MGS Unit 17: No P&A operations were performed on this well. The plan is to keep it active as a Class II disposal well for the remainder of the P&As and then P&A this well last. A sundry for P&A is submitted to AOGCC and pending approval. 11 S MGS Unit 18: The reservoir was plugged with LCM by the previous operator. A variance to leave this plug in place was approved by AOGCC in the P&A Sundry application. The production tubing SS was verified to have integrity with a plug set @ 11,340' SLIM and PT'd to 500 psi. The tubing LS had a 2" CT jet pump completion installed in it to surface. To verify that the CT x LS had integrity sufficient for a fullbore cement job a temperature tool was run on EL down the SS to—11,332' SLM. FIW (Filtered Inlet Water) was pumped down the CT with returns from the IA. A temperature shift at the tool was noted indicating circulation to below that depth. FIW was pumped down the CT with returns from the LSxCT annulus but the temperature shift could not be read from the SS. A dyed pill of FIW was pumped down the CT with returns from the LSxCT annulus. The pill came badk @ 71 bbls away indicating a circulation depth of at least —9340' MD. The LSxCTxSSxlA was PT'd to 500 psi and verified to have very low injectivity (0.1 bpm @ 500 psi). The OA and OOA were PT'd to 500 psi and verified to have no injectivity, however there was a one-way leak from the OA to the OOA. Temperature and acoustic tools were run on EL to locate the leak with no anomalies noted. Diesel was pumped down the OA with returns from the OOA and diesel returns were observed @ 2.9 bbls away indicating the OA x DOA (13-3/8" casing) leak was within 15' of surface. The TOC in the ODA was observed at the OOA outlet. The lower cement plug was planned to be —6250' in length and circulated down the CT and up the IA, the LSxCT annulus, and up the SS, balanced in all tubing strings and IA. This cement plug was pumped as planned however when returns were taken from the SS of tubing cement immediately bridged off the circulation path. The excess cement (55 bbls) was circulated up the IA. This put the expected TOC in the IA —1000' shallower @ —4000' MD. The TOC was tagged in the Cr @ 6840'. The planned TOC was —5000' MD. The SS drifted clean to 11,268' SLIM. A revised Sundry was submitted to lay a cement plug in the SS of tubing commensurate with the planned cement top in the IA, LS, and Cr. This was approved but it was found that the wellhead arrangement would not allow for rigging up Cr on the SS of tubing with the CT hanger installed. Another revision was issued to cut and pull —400' of the CT and remove the CT hanger in the process. This was executed without issue, and CT rigged up on the SS and laid in the planned cement plug without issue. The TOC in the SS of tubing was tagged @ 5100' MD. The planned TOC was 5000' MD. The AOGCC witnessed CMIT of the LSxSSxIA passed. The LS, SS, 9-5/8", and 13-3/8" casings were perforated @ —400' MD in preparation for the surface cement job. Winter weather conditions prevailed and the LSxSSxIAxOA was freeze -protected with diesel to —120' MD. The well pressures will be monitored through the winter months with monthly pressure -reads and then the P&A will be finished next Spring. 12 3 AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of Hilcorp Alaska's ) Plugging and Abandonment Plans for Wells ) in the Baker, Dillon and Spur Platforms ) in the Cook Inlet Offshore. ) __________________________________________) Docket number: OTH 22-005 PUBLIC HEARING March 29, 2022 10:00 o'clock a.m. BEFORE: Jeremy Price, Chairman Jessie Chmielowski, Commissioner Daniel T. Seamount, Commissioner AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chairman Price 03 3 Testimony by Mr. Worthington 05 4 Testimony by Ms. Hughes 09 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIRMAN PRICE: Good morning. We're now on 4 record. It is approximately 10:00 a.m., Tuesday, March 5 29th, 2022. This is Jeremy Price, Chairman and 6 Commissioner. With me today are Commissioners Dan 7 Seamount and Jessie Chmielowski. This is a public 8 hearing on docket number OTH 22-005, Hilcorp's plugging 9 and abandonment plans for wells in the Baker, Dillon 10 and Spur platforms in the Cook Inlet offshore. This 11 hearing is being held in accordance with Alaska statute 12 44.62 and 20 AAC 25.540 of the Alaska Administrative 13 Code. 14 The notice of the hearing for OTH 22-004 was 15 published in the state of Alaska online notices website 16 as well as the AOGCC's website and was sent through the 17 AOGCC email list serve on February 10th, 2022. The 18 AOGCC also published the notice in the Anchorage Daily 19 News on February 13th, 2022. To date AOGCC has not 20 received any public comments on the matter. 21 Today's hearing is being held in person, 22 telephonically and via Microsoft Teams so please be 23 mindful of any background noise and make sure you are 24 muted when you're not testifying or addressing the 25 Commission. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 4 1 If you require any other special accommodation 2 please contact Samantha Carlisle. She can be reached 3 at 907-793-1223 or you can send her a message through 4 the Microsoft Teams chat icon and she will do her best 5 to accommodate you. 6 Samantha Carlisle will be recording the 7 hearing, Computer Matrix will prepare the transcript 8 and upon completion and preparation of the transcript 9 persons desiring a copy will be able to obtain it by 10 contacting Computer Matrix. 11 Before asking Hilcorp to provide their 12 presentation do any of the Commissioners have any 13 questions? 14 Commissioner Chmielowski. 15 COMMISSIONER CHMIELOWSKI: No, thank you. 16 COMMISSIONER SEAMOUNT: I have none. Thank 17 you. 18 CHAIRMAN PRICE: Okay. Mr. Worthington, Ms. 19 Hughes, are you ready to proceed. If you don't mind 20 please state your name for the record, raise your right 21 hand and -- yeah, good, please stand if you don't mind. 22 MR. WORTHINGTON: Aras Worthington, Hilcorp 23 Alaska. 24 MS. HUGHES: Vanessa Hughes, Hilcorp Alaska. 25 CHAIRMAN PRICE: Thank you. Please raise your AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 5 1 right hand. 2 (Oath administered) 3 IN UNISON: I do. 4 CHAIRMAN PRICE: Thank you. Please be seated. 5 Okay. I think we're ready. 6 ARAS WORTHINGTON 7 called as a witness on behalf of Hilcorp Alaska, 8 testified as follows on: 9 DIRECT EXAMINATION 10 MR. WORTHINGTON: Good morning, Mr. Chairman, 11 Commissioners and AOGCC staff. My name is Aras 12 Worthington. I am senior technical advisor for Hilcorp 13 Alaska operations for Hilcorp Alaska. I'm here with 14 Vanessa Hughes, asset team leader of Kenai for Hilcorp 15 Alaska. Thank you for the opportunity today to present 16 testimony in support of Hilcorp's request to pursue 17 Dillon platform well plug and abandonments in 2022 in 18 place of Spur platform well abandonments in 2022. 19 I'm a nearly lifelong Alaskan with a bachelor 20 of science in mechanical engineering from Purdue 21 University in West Lafayette, Indiana. I'm a licensed 22 petroleum engineer in the state of Alaska, I have 28 23 years of engineering oilfield experience within a wide 24 variety of oilfield service and production companies in 25 the fields of interventions, rig workovers, coiled AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 6 1 tubing drilling, plug and abandonments and well 2 integrity. I also led the annual programs for plug and 3 abandonment of over 60 wells in the greater Prudhoe Bay 4 in roughly the last decade and have experience in both 5 onshore and offshore well abandonments. 6 I respectfully request that the Commission 7 recognize me as an expert witness in this matter. 8 CHAIRMAN PRICE: Any questions on the witness' 9 background, education? 10 COMMISSIONER SEAMOUNT: I have none and I have 11 no objections. 12 COMMISSIONER CHMIELOWSKI: No questions, no 13 objections. 14 CHAIRMAN PRICE: The Commission recognizes you 15 as an expert witness. 16 MR. WORTHINGTON: Okay. Thank you. Hilcorp 17 currently operates 15 platforms in the Cook Inlet. Of 18 these 15 platforms four are lighthouse -- in lighthouse 19 mode meaning they no longer produce any hydrocarbons, 20 are unmanned and have only corrosion protection and 21 navigation lights operating on the platforms. The 22 Baker, Dillon, Spark and Spur platforms are in 23 lighthouse mode. The Baker platform in the Middle 24 Ground Shoal field has 25 wells, many of which have at 25 least one cement abandonment plug installed. The AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 7 1 Dillon platform, also in the Middle Ground Shoal field 2 has 17 wells, only one of which has a cement 3 abandonment plug installed. The Spur platform in the 4 North Trading Bay field has nine wells all of which 5 have at least one cement abandonment plug installed. 6 The Spark platform has eight wells and is the only 7 platform for which all of the wells have been plugged 8 and abandoned. 9 The focus of this hearing is on the three 10 platforms with wells that are not fully plugged and 11 abandoned, the Baker, Dillon and Spur platform. 12 In 2017 Hilcorp submitted applications to renew 13 suspensions on all Spur platform wells. AOGCC 14 responded requiring that plug and abandonment plans 15 must be submitted in order to approve well suspensions. 16 Hilcorp responded with a timeline to do platform 17 repairs in preparation for well plug and abandonment 18 activities which would commence in July of 2021. 19 Hilcorp has largely held to that timeline albeit one 20 year behind due to unforeseen issues with platform 21 equipment. Hilcorp is currently in a position where 22 Spur well abandonments be commenced and completed in 23 2022. However after risk ranking all three of these 24 idle platforms and their wells, Hilcorp has requested 25 that the wells be plugged and abandoned based on risk AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 8 1 ranking both of the wells and the platform integrity. 2 The platform integrity risk assessments took 3 into account the following factors. One, condition of 4 the platform legs; two, condition and presence of 5 corrosion leg wraps; three, local water current 6 velocity; four, ice loading on the legs from the 7 current; five, consistency of cathodic protection of 8 the legs; six, the differences in design of the leg 9 cross-bracing; seven, corrosion of the leg cross- 10 bracing. 11 The well risk assessments took into account the 12 following factors. Number 1, the current integrity of 13 the well completion; number 2, the current shut in 14 tubing and wellhead pressures; three, the presence of 15 gas or oil in the perforated reservoirs; four, status 16 of cement plugs installed in the wells; and five, known 17 issues with access to the wellbore. 18 Of the three platforms the risk ranking from 19 highest to lowest on both the platform and the well 20 bases is as follows. Dillon, Baker and lastly Spur. 21 Hilcorp intends to have annual well plug and 22 abandonment campaigns for the next several years. 23 Therefore we wish to abandon wells prioritized on our 24 highest to lowest risk bases, thus the request to 25 execute Dillon wells first, followed by Baker and AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 9 1 finally Spur. 2 Hilcorp has communicated this to the AOGCC and 3 has participated in meetings with Commissioners and 4 staff to communicate and answer questions on this 5 subject. Hilcorp has proposed that the Dillon wells 6 P&As be executed in 2022, the Baker wells in 2023 and 7 the Spur wells in 2024. 8 I'll now hand over to Vanessa Hughes, asset 9 team leader for Kenai and Hilcorp Alaska. 10 VANESSA HUGHES 11 previously sworn, called as a witness on behalf of 12 Hilcorp Alaska, testified as follows on: 13 DIRECT EXAMINATION 14 MS. HUGHES: Good morning, Mr. Chairman, 15 Commissioners, AOGCC staff. My name is Vanessa Hughes, 16 I'm an asset team leader for the Kenai team, both 17 onshore and offshore. I obtained my petroleum 18 engineering degree from the University of Texas at 19 Austin in 2007, joining Hilcorp immediately upon 20 graduating when the company was a quarter of the size 21 it is today. I have lived and worked in Alaska for the 22 last eight years. 23 I respectfully request that the Commission 24 recognize me as an expert witness in this matter. 25 CHAIRMAN PRICE: Thoughts from Commissioners, AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 10 1 questions. 2 COMMISSIONER SEAMOUNT: I have no questions, no 3 objections. 4 COMMISSIONER CHMIELOWSKI: How many years of 5 experience do you have total? 6 MS. HUGHES: Fifteen years. 7 COMMISSIONER CHMIELOWSKI: Fifteen years. No 8 objections. 9 CHAIRMAN PRICE: The Commission recognizes you 10 as an expert witness. 11 MS. HUGHES: Our mission at Hilcorp is to 12 unlock energy for the betterment of our employees and 13 our communities. Since 2012 I believe we have 14 accomplished just that in the Cook Inlet. We have 15 extended gas supply another 10 years by investing over 16 $650 million on gas development. We've spent over $300 17 million drilling offshore for oil, further reducing 18 waste of Alaska resources while utilizing existing 19 infrastructure. The Inlet communities thrive in part 20 due to the many jobs provided by our investment 21 activity. I'm proud of what Hilcorp has accomplished 22 in the last 10 years in the Cook Inlet. Unlocking 23 energy from late life fields reduces waste and aids 24 Alaska into a smooth transition into more sustainable 25 energy sources. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 11 1 As responsible operators we restored our fields 2 to their economic life, a longevity extended in part 3 due to diligent cost management. Despite our best 4 efforts the Cook Inlet is a high cost, high sensitivity 5 environment with complex regulatory requirements. 6 After many years of subsurface technical evaluation 7 Hilcorp's now able to say that economically recoverable 8 reserves from Baker, Dillon and Spur have reached their 9 economic limits. With that information in hand and as 10 Aras explained we risk assessed these platforms to 11 prioritize our P&A efforts. 12 With that I'll hand it over to Aras for 13 concluding remarks. 14 MR. WORTHINGTON: Aras Worthington again. 15 Hilcorp acknowledges that the AOGCC has a priority to 16 progress the safe and compliant abandonment of wells on 17 idle platforms. Hilcorp has also progressed to 18 prioritize the safe and compliant well abandonments 19 where recoverable reserves have reached their economic 20 limits. 21 Hilcorp intends to execute annual well plug and 22 abandonment campaigns in the Cook -- idle Cook Inlet 23 platforms 24 that we no longer intend to produce hydrocarbons from. 25 We respectfully request that the platform well AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 12 1 abandonment be prioritized on a risk mitigation basis. 2 (Off record comments - microphone) 3 As previously communicated Hilcorp proposes to 4 execute abandonments in the following order. Dillon 5 platforms in 2022, Baker platforms in 2023, Spur 6 platform wells in 2024. 7 Thank you for your time and consideration. We 8 are open to questions from the Commission at this time. 9 COMMISSIONER CHMIELOWSKI: Thank you. Just to 10 confirm, Dillon platform is the highest risk for 11 platform integrity and well risk; is that correct? 12 MR. WORTHINGTON: That is correct. 13 COMMISSIONER CHMIELOWSKI: And then Baker 14 second for both of those items also..... 15 MR. WORTHINGTON: Yes. 16 COMMISSIONER CHMIELOWSKI: .....second 17 priority? Okay. 18 MR. WORTHINGTON: Aras Worthington. Yes. 19 COMMISSIONER CHMIELOWSKI: And you mentioned 20 that, you know, the Spur platform P&As had been delayed 21 due to mechanical issues on the platform, I think it 22 was the crane. Are there any issues on Dillon or Baker 23 or have -- has that been confirmed that all the 24 equipment you would need is operational? 25 MR. WORTHINGTON: The equipment is all AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 13 1 operational, it's an ongoing effort to get everything 2 ready for this spring, but everything is progressing as 3 planned. 4 COMMISSIONER CHMIELOWSKI: Okay. Is there any 5 potential for, you know, future development from these 6 platforms, is there any, you know, hydrocarbon 7 potential in different reservoirs that you're aware of? 8 MS. HUGHES: Not economically. 9 COMMISSIONER CHMIELOWSKI: Not economically? 10 MS. HUGHES: Correct. This is Vanessa. 11 COMMISSIONER CHMIELOWSKI: There have been 12 some, you know, leak issues with subsea pipelines in 13 the Cook Inlet. Has -- do these platforms tie in to 14 that system and has that played a role in this decision 15 to abandon these platforms? 16 MR. WORTHINGTON: These platforms do not tie in 17 to that system..... 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. WORTHINGTON: .....and it does not play a 20 role in this. 21 COMMISSIONER CHMIELOWSKI: Okay. There's 22 another question about a couple of wells on the Spur 23 platform. I think there were two wells that did not 24 meet suspended well regulations and I think one 25 required a -- a wellhead and pressure monitoring AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 14 1 equipment. Has that been done? 2 MR. WORTHINGTON: It's not completely done at 3 this time I don't believe, but it's very close. I can 4 get you an update afterwards. 5 COMMISSIONER CHMIELOWSKI: Okay. Those are all 6 the questions I have currently. 7 COMMISSIONER SEAMOUNT: When you say that 8 Dillon is at risk because of the integrity of the 9 platform, do you have any idea how long those platforms 10 would last if they were not abandoned. Do you have 11 any estimates on that, I mean, I -- I guess what I'm 12 getting to is are they reusable. You say there's no 13 economics to further development, I worked on those 14 platforms for eight years and there's a ton of oil left 15 there. And admittedly it was not the best -- not 16 developed correctly so that oil may not be economically 17 recoverable, but where all that oil's coming from is 18 down the Jurassic. And the oil companies and the state 19 have been remiss over the years in not actually going 20 after where the oil is generated. And I've always 21 thought that those platforms could be -- you know, a 22 nonutilized wellbore could be drilled 4,500 feet deeper 23 to see if there's something there. Have you guys 24 thought about anything like that, I mean, if the 25 platform's about ready to fall over then yeah, you need AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 15 1 to get out of there, but they might be able to use some 2 sort of drilling platform. Have you guys thought about 3 anything like that? 4 MS. HUGHES: Mr. Chairman, this is Vanessa. Is 5 the question whether we've considered future use of the 6 platform itself or whether or not we would consider 7 further resource development from the platform? 8 COMMISSIONER SEAMOUNT: Yes. 9 MS. HUGHES: Okay. 10 COMMISSIONER SEAMOUNT: I guess my question is 11 this the -- basically is this the end of those 12 platforms, you're -- you're declaring memorial for 13 them? 14 MS. HUGHES: Well, as it relates to the 15 subsurface resource yes, we deem it to be economically 16 nonviable. However as to the structure of the platform 17 itself, it's something that we're evaluating and 18 possibly we could discuss at a later time. 19 COMMISSIONER SEAMOUNT: Okay. So it's not 20 really -- they're not really dead yet, but they're in 21 critical condition? 22 MR. WORTHINGTON: The platforms -- sorry Aras 23 Worthington here. You mentioned about to fall over, 24 that -- that's not correct, they're -- they're not -- 25 you know, we ranked the platform -- of these platforms AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 16 1 we ranked them all by integrity risk and deemed Dillon 2 to be the highest risk. We also deem it to be suitable 3 to do P&A work and install a temporary cam and pursue 4 well work just like there would be for production this 5 summer when we're doing P&As. So it -- it's not that 6 it's falling apart, it's just that it ranks the worst 7 of those three platforms on an integrity basis. 8 COMMISSIONER SEAMOUNT: There was a rumor out 9 there that Dillon was planned and then the '64 10 earthquake hit and then they put it in and because of 11 the earthquake the ground had sunk and so that's why 12 it's so low off the water. I don't know if that's true 13 or not. 14 MR. WORTHINGTON: I don't know either honestly. 15 Sorry. 16 COMMISSIONER CHMIELOWSKI: Well, I guess along 17 that line are there plans to decommission or remove the 18 platforms or is there anything planned for the 19 structures themselves? 20 MR. WORTHINGTON: We're study -- Aras 21 Worthington, Commissioner Chmielowski. We're studying 22 the dismantlement, removal and remediation of those 23 platforms. We don't have an immediate plan at this 24 time. 25 COMMISSIONER CHMIELOWSKI: Okay. Thanks. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 17 1 CHAIRMAN PRICE: Anything -- what are some of 2 the factors that might delay your P&A schedule for 3 Dillon at '22, Baker at '12 and Spur at '24, what kind 4 of conditions might push that? Because the reason I 5 ask is the AOGCC had said -- a fair bit of history with 6 even previous operators and -- and the effort to try 7 and take care of these wells that haven't been 8 producing for years and years and years. So I think 9 there's definitely an interest to seeing, you know, 10 these wells getting taken care of sooner rather than 11 later. So what are some of the factors that might 12 delay those timelines? 13 MR. WORTHINGTON: We haven't -- Aras 14 Worthington. We haven't executed a full platform P&A 15 program, Hilcorp hasn't yet, that's going to be this 16 summer. There will be learnings. I don't have a 17 crystal ball, but my expectation -- our expectation is 18 we'll get it all done this season. It's possible that 19 it could take longer than we think and I -- I can't 20 really offer anything more than that and do everything 21 we can to get them -- get them completed this summer 22 and then Baker next summer. It's very doable from a 23 wellwork standpoint, logistics and everything else. 24 But the unforeseen, I don't know. 25 CHAIRMAN PRICE: Yeah. Okay. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 18 1 MS. HUGHES: This is Vanessa. We have seen one 2 example of something that could impact, but hard to 3 determine, is labor shortages. With the activity -- 4 the increase in activity recently we have -- we have 5 had challenges around labor. So that's one potential. 6 At the moment we don't see that as being an issue, 7 but..... 8 CHAIRMAN PRICE: Okay. 9 MS. HUGHES: .....it is potential. 10 CHAIRMAN PRICE: Ms. Hughes, when you talked 11 about the high cost, complex regulatory environment 12 when -- in your statement that the wells had reached 13 the end of their useful life, is that because of -- can 14 you elaborate on that a little bit I guess, I'm trying 15 to -- when you say complex regulatory environment, is 16 that multiple jurisdictions, is it any particular 17 regulations or agencies that are impacting the economic 18 useful life of those wells? 19 MS. HUGHES: Sure. I'll address the first 20 piece, the high cost in -- it's an offshore environment 21 in the Inlet. It requires boats, helicopters, 22 logistics are difficult, you know, ice conditions in 23 the winter, small windows of opportunity to get capital 24 work done. Those are all factors in the high cost 25 environment. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 19 1 As to the regulatory requirements, there are 2 several agencies that have jurisdiction, not all of 3 them agree about what they would like to see from us 4 all the time. So usually that means -- it translates 5 primarily to delays, takes longer to get things done. 6 We are committed to being -- to meeting all regulatory 7 requirements so that also takes more, you know, 8 horsepower internally to ensure we understand what is 9 required and that we're following those requirements. 10 Delays, you know, time, personnel, all those 11 things impact the -- the longevity of these fields. 12 CHAIRMAN PRICE: Thank you. Any other 13 questions from Commissioners at this time. 14 COMMISSIONER SEAMOUNT: I have none. 15 COMMISSIONER CHMIELOWSKI: I have none. 16 CHAIRMAN PRICE: For folks on the line we'd 17 specifically like to take a 10, 15 minute break and 18 discuss with senior staff any issues or questions that 19 we may need to ask before we close the hearing. But 20 before we do that I'd like to open the opportunity for 21 the public to testify. If there's anyone online who 22 wishes to testify on the matter please unmute your 23 phone and state your name for the record at this time. 24 (No comments) 25 CHAIRMAN PRICE: Anybody on the chat? AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 20 1 MS. CARLISLE: No. 2 CHAIRMAN PRICE: How about in the room, anyone 3 in the room wishing to testify at this time? 4 (No comments) 5 CHAIRMAN PRICE: Okay. In that case it's -- 6 the time is about 10:24. We'll reconvene in 15 7 minutes. 8 Thank you. 9 (Off record) 10 (On record) 11 CHAIRMAN PRICE: Okay. We're back in session, 12 it's -- it took a little longer than we thought, it's 13 about 10:43. 14 Just a couple of additional questions. One 15 question came in from a representative from DNR, I'll 16 try to pronounce the name, Chalinda Weerasinghe. 17 Questions are -- a couple of questions please from the 18 testimony presented. It is my understanding that the 19 uneconomic nature of production at Dillon, Baker and 20 Spur is not due to diminished economic resource, end of 21 field life, but mainly due to the cost of environment 22 present. Would this be a fair statement. And what is 23 the likelihood of finding slash exploring unproven 24 resources that might be accessible from those 25 platforms. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 21 1 MS. HUGHES: This is Vanessa. There's -- as it 2 relates to the resource there's a range of uncertainty 3 as to how much is in the ground and that's one of the 4 inputs in determining the economic life of these 5 fields. So yes, it does play a role. What we 6 determine to be that range does play a role in the 7 economic life as well as the cost. Both of those are 8 variables in the equation. 9 COMMISSIONER SEAMOUNT: Have you been engaged 10 with DNR, involved in keeping them in the loop on what 11 your plans are with these platforms? 12 MR. WORTHINGTON: Aras Worthington. We submit 13 a plan of development every year to DNR on all the 14 platforms and fields. 15 COMMISSIONER SEAMOUNT: Okay. Thank you. 16 COMMISSIONER CHMIELOWSKI: Yeah, and just a 17 quick clarification. As you know AOGCC has regulations 18 for well plugging and abandonment and also for site 19 clearance. So just to confirm that Hilcorp is 20 proposing to plug and abandon the wells, but not 21 perform offshore site clearance at this time as the 22 platforms will remain; is that correct? 23 MR. WORTHINGTON: Aras Worthington. That is 24 correct..... 25 COMMISSIONER CHMIELOWSKI: Okay. Thank you. AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 22 1 MR. WORTHINGTON: .....Commissioner 2 Chmielowski. 3 CHAIRMAN PRICE: Sam, any additional questions 4 coming on the chat? 5 MS. CARLISLE: (Inaudible response)..... 6 CHAIRMAN PRICE: Okay. Any additional 7 questions from Commissioners? 8 COMMISSIONER SEAMOUNT: Not I. Thank you. 9 COMMISSIONER CHMIELOWSKI: Nope. 10 CHAIRMAN PRICE: Do you guys have anything else 11 you want to say before we close the hearing or any need 12 to keep it open for any reason? 13 (No comments) 14 CHAIRMAN PRICE: Okay. In that case we will 15 adjourn. The time is 10:46. 16 (Hearing adjourned - 10:46 a.m.) 17 (END OF PROCEEDINGS) 18 19 20 21 22 23 24 25 AOGCC 3/29/2022 ITMO: HILCORP ALASKA DOCKET No. OTH-22-005 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 23 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 23 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket number: OTH 22-005, transcribed under my 6 direction from a copy of an electronic sound recording 7 to the best of our knowledge and ability. 8 9 _______________ _______________________________ 10 DATE SALENA A. HILE, (Transcriber) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 [10:28 AM] Weerasinghe, Chalinda D (DNR) A couple of questions please: From the testimony presented, it is my understanding that the uneconomic nature of production at Dillon, Baker and Spur is not due to diminished economic resource (end of field life), but mainly due to the cost environment present. Would this be a fair statement? What is the likelihood of finding/exploring unproven resources that might be accessible from those platforms? 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: OTH-22-005 Hilcorp’s plugging and abandonment (P&A) plans for wells on the Baker, Dillon, and Spurr platforms in the Cook Inlet Offshore (CIO). The Alaska Oil and Gas Conservation Commission (AOGCC) on its own motion is setting a public hearing to discuss Hilcorp’s P&A plans for wells on the Baker, Dillon, and Spurr platforms in the CIO. This notice does not contain all the information. You may obtain more information about this matter by contacting the AOGCC’s Executive Secretary, Samantha Carlisle, at (907) 793-1223 or samantha.carlisle@alaska.gov. The AOGCC has scheduled a public hearing on this matter for March 29, 2022, at 10:00 a.m. at 333 West 7th Avenue, Anchorage, AK 99501. The hearing, which may be changed to virtual in the event of COVID19 health and safety concerns, will be held in the AOGCC hearing room located at 333 West 7th Avenue, Anchorage, AK 99501. The audio call in information is (907) 202 7104 conference ID: 277 737 046#. Anyone who wishes to participate remotely using MS Teams video conference should contact Samantha Carlisle at least two business days before the scheduled public hearing to request an invitation for MS Teams. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 7th Avenue, Anchorage, AK 99501 or samantha.carlisle@alaska.gov. Comments must be received no later than the conclusion of the March 29, 2022, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact Samantha Carlisle, at (907) 793-1223, no later than March 22, 2022. Jeremy M. Price Chair, Commissioner Jeremy Price Digitally signed by Jeremy Price Date: 2022.02.09 16:24:12 -09'00' 1 Carlisle, Samantha J (OGC) From:Carlisle, Samantha J (OGC) Sent:Thursday, February 10, 2022 8:01 AM To:AOGCC_Public_Notices Subject:Public Hearing Notice, OTH-22-005, Hilcorp Attachments:OTH-22-005 Public Hearing Notice.pdf Docket Number: OTH-22-005 Hilcorp’s plugging and abandonment (P&A) plans for wells on the Baker, Dillon, and Spurr platforms in the Cook Inlet Offshore (CIO). Samantha Carlisle Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 Mailed 2/10/22 SJC 1 1 Carlisle, Samantha J (OGC) From:McLellan, Bryan J (OGC) Sent:Thursday, January 20, 2022 4:41 PM To:Aras Worthington Cc:Vanessa Hughes; Dan Marlowe; Chad Helgeson; Josh Allely - (C) Subject:RE: CIO P&A Plan for 2022 Aras, The AOGCC conditionally approves Hilcorp’s request to delay the P&A of the wells on Spurr platform until 2024. The AOGCC had previously required all Spurr platform wells to be abandoned in 2022. This approval is conditional on the following: 1. Well P&A activity begins at Dillon platform as soon as ice conditions in the inlet allow in 2022 and is continued in earnest throughout the ice‐free season. If for some reason P&A activity can not begin on Dillon platform (because of platform condition or some other unforeseen issue), then P&A activity at Baker will take place according to the same timeline. 2. Spurr 05RD3 must have a tree and pressure monitoring equipment installed as soon as feasible in 2022. 3. Pressure monitoring checks to take place on all Spurr Wellheads on a monthly basis from now until the wells at Spurr are P&A’d. AOGCC is to be given an opportunity to witness the monthly platform checks. Results of the monthly checks to be sent to the AOGCC. 4. Suspension sundries for Spurr platform wells expired on 12/31/21 and will not be renewed because the wells have no future utility and therefore do not meet criteria for a suspended well. To address the lack of clear status for the Spurr wells while they wait for P&A, the AOGCC plans to issue an order that lays out the timeline for Spurr well abandonment. 5. Prior to issuing the order, AOGCC will schedule a hearing on Hilcorp’s Cook Inlet P&A plans for Dillon, Baker and Spurr. There is public interest in the P&A of these platforms and Hilcorp can provide information for the public record through the hearing process. 6. Periodic progress reports to be provided to AOGCC on a schedule to be determined during the public hearing process. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Tuesday, January 11, 2022 10:48 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: FW: CIO P&A Plan for 2022 Bryan, CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 Please see attached platform information sheet and answers below. As discussed, Hilcorp requests that information produced pursuant to the AOGCC’s request be exempt from an Alaska Public Records request and is submitted subject to AS 43.90.150 and AS 43.90.22(e), and all federal counterparts, as well as any confidentiality provisions under AS 31.05.035 and 20 AAC 25.537. 1. Information on the structural integrity of each of the 3 platforms. See attached Platform Summary. 2. Information regarding the platform’s condition and readiness to begin P&A work. Four years were required to get Spurr platform in a condition that can support the P&A campaign. a. Are the cranes and work surfaces and helideck on Baker and Dillon ready to begin P&A next year? The cranes and helidecks on both platforms are operational. b. Are inspections needed to confirm their status? No additional Integrity inspections are needed. 3. The risk assessment for the 3 platforms that informs Hilcorp’s proposed P&A schedule. See attached Platform Summary. The well‐risk summary is based on well integrity, surface pressures, gas or oil well, and known intervention issues. This is summarized as follows from highest to lowest risk: Dillon, Baker, Spurr. 4. Is there potential undeveloped hydrocarbon resources that could be accessed from Baker or Dillon platforms? If so, could new drilling targets be drilled from the existing Baker and Dillon platforms, even if the existing wells are P&A’d? Yes. These resources could be drilled from the open well slots left after P&A of the other wells from either platform ‐ pending economic evaluation. 5. Explain how the subsea pipelines have played into Hilcorp’s decision to abandon Baker and Dillon platforms? See attached Platform Summary for pipeline information. While pipeline status is a factor in deciding which platforms to pursue hydrocarbon production from, it is certainly not the only factor. Several re‐ start projects at Baker have been proposed over the years however none were sufficiently economically viable. Platform facility work, platform Integrity work, platform camps, cost of manning a platform, reservoir status, well work, as well as pipeline status are all significant factors. If the AOGCC approves Hilcorp’s proposed CIO P&A plan, Hilcorp will be required to submit Suspension renewal Sundries for all the wells on Spurr platform.  The Spurr Suspension renewal sundries will be conditional on work progressing annually on the P&A of Baker and Dillon. Understood.  Work will be required in 2022 on wells SPR‐05RD2 and SPR‐07 to meet the Suspended Well regulations in 20 AAC 25.110. We would like to discuss the scope of the work AOGCC would like done. Ideally, cementing P&A operations on Spurr would be in one campaign to fully P&A all of the wells in a future year as proposed earlier. This is more efficient, lowers the risk of the program, and obviously is more cost‐effective. However, we can address wellhead/gauge issues on these wells in 2022 without mobilizing heavy wellwork equipment to the platform. Please let us know in advance of the meeting if there is further detail needed by Commissioners to inform your decision. Thanks and Best Regards, Aras Worthington Hilcorp Alaska LLC Senior Technical Advisor for Alaska Operations, PE Aras.worthington@hilcorp.com 907‐564‐4763 907‐440‐7692 mobile From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, January 6, 2022 9:49 AM To: Aras Worthington <Aras.Worthington@hilcorp.com> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson 3 <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: [EXTERNAL] RE: CIO P&A Plan for 2022 Aras, Commissioners are open to the idea of rearranging the order of the CIO P&A program, but would like to meet with Hilcorp to discuss the rationale. I’ll set up a meeting next week, but in advance of the meeting, please submit the following information to help make a decision: 1. Information on the structural integrity of each of the 3 platforms. 2. Information regarding the platform’s condition and readiness to begin P&A work. Four years were required to get Spurr platform in a condition that can support the P&A campaign. a. Are the cranes and work surfaces and helideck on Baker and Dillon ready to begin P&A next year? b. Are inspections needed to confirm their status? 3. The risk assessment for the 3 platforms that informs Hilcorp’s proposed P&A schedule. 4. Is there potential undeveloped hydrocarbon resources that could be accessed from Baker or Dillon platforms? If so, could new drilling targets be drilled from the existing Baker and Dillon platforms, even if the existing wells are P&A’d? 5. Explain how the subsea pipelines have played into Hilcorp’s decision to abandon Baker and Dillon platforms? If the AOGCC approves Hilcorp’s proposed CIO P&A plan, Hilcorp will be required to submit Suspension renewal Sundries for all the wells on Spurr platform.  The Spurr Suspension renewal sundries will be conditional on work progressing annually on the P&A of Baker and Dillon.  Work will be required in 2022 on wells SPR‐05RD2 and SPR‐07 to meet the Suspended Well regulations in 20 AAC 25.110. Let me know how much time you need to prepare for this meeting and then I’ll send out an invite. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Thursday, December 30, 2021 10:32 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: CIO P&A Plan for 2022 Bryan, As you are aware work has been ongoing to complete the abandonment work on the Spurr platform. Thus far we have largely stuck to our timeline, albeit one year behind schedule due to unforeseen issues with the unit crane. To date we have completed all the major objectives through original planned activity for 2020 and are now in a position where we could proceed with the downhole work. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 4 Hilcorp has risk‐assessed the idle platforms and wells in the Cook Inlet Offshore asset (Baker, Dillon, Spark, and Spurr platforms). These risk assessments indicated that the Dillon wells were the highest risk in that group. The main reason for the Dillon wells being higher risk than Spurr is that most of the Dillon wells do not have any cement plugs in them, whereas all of the Spurr wells do have at least one cement plug between the reservoir and surface. Hilcorp therefore proposes to shift our P&A focus from the Spurr platform to the Dillon platform and plan to fully P&A all of the wells on Dillon in 2022. Hilcorp plans to have funding available for that purpose. If for some unknown operational reason the funding cannot be used on Dillon, then Hilcorp will use that funding to complete P&As on the Baker platform. We say this only to make clear that we are committed to having a platform P&A campaign in the Cook Inlet Offshore asset in 2022 and make good on progressing well P&As. Hilcorp proposes the following year‐by‐year P&A campaigns: 2022: CI‐17589 and Dillon Wells 2023: Baker Wells 2024: Spurr Wells Whether it be Dillon, Baker, or Spurr, Hilcorp is committed to dedicating resources to keep the P&A campaign going until the wells on the aforementioned platforms have been fully abandoned. Thanks for your consideration. Aras Worthington Hilcorp Alaska LLC Senior Technical Advisor for Alaska Operations, PE Aras.worthington@hilcorp.com 907‐564‐4763 907‐440‐7692 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Carlisle, Samantha J (OGC) From:McLellan, Bryan J (OGC) Sent:Thursday, January 20, 2022 4:09 PM To:Aras Worthington Cc:Vanessa Hughes; Dan Marlowe; Chad Helgeson; Josh Allely - (C) Subject:RE: [EXTERNAL] RE: CIO P&A Plan for 2022 Aras, Since the platform risk assessment was specifically requested by the AOGCC and it is information that supports Hilcorp’s proposed P&A schedule, it is not deemed to be voluntarily submitted. Reference 20 AAC 25.300 for information requests. However, the AOGCC will give Hilcorp the opportunity to provide an independent basis about why the information should be held confidential. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Wednesday, January 19, 2022 12:48 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: RE: [EXTERNAL] RE: CIO P&A Plan for 2022 Bryan, Hilcorp’s justification for why this material should be treated as confidential is that this information was provided voluntarily. Please reference cited regulations below. 20 AAC 25.537 - Public and confidential information: (a) The commission will routinely make available to the public, by means of records or reports, in its offices or elsewhere, or by means of regular publication, the following information: (1) surface and proposed bottom-hole locations of each well after approval of the Permit to Drill (Form 10-401); (2) total depth, bottom-hole location and well status after the Well Completion or Recompletion Report and Log (Form 10-407) is filed; (3) all reports and information required by this chapter for development and service wells; (4) regular production data and regular production reports, as required to be filed by the operator each month; (5) injection data and injection reports, as required to be filed by the operator each month; and (6) all data filed on a well as required by this chapter upon expiration of the confidential period described in (d) of this section. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 2 (b) Engineering, geologic, geophysical, and other commercial information not required by this chapter, but voluntarily filed with the commission will be kept confidential if the person filing the information so requests. This subsection does not apply to information submitted in a public hearing under 20 AAC 25.540. Please let me know if this is acceptable to AOGCC as grounds for confidentiality. Thanks and Best Regards, Aras Worthington Hilcorp Alaska LLC Senior Technical Advisor for Alaska Operations, PE Aras.worthington@hilcorp.com 907‐564‐4763 907‐440‐7692 mobile From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, January 11, 2022 1:10 PM To: Aras Worthington <Aras.Worthington@hilcorp.com> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: [EXTERNAL] RE: CIO P&A Plan for 2022 Aras, Hilcorp has requested that the platform summary sheet you’ve submitted be held confidential. You’ll need to provide justification as to why this information should be treated as confidential. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Tuesday, January 11, 2022 10:48 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: FW: CIO P&A Plan for 2022 Bryan, Please see attached platform information sheet and answers below. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 3 As discussed, Hilcorp requests that information produced pursuant to the AOGCC’s request be exempt from an Alaska Public Records request and is submitted subject to AS 43.90.150 and AS 43.90.22(e), and all federal counterparts, as well as any confidentiality provisions under AS 31.05.035 and 20 AAC 25.537. 1. Information on the structural integrity of each of the 3 platforms. See attached Platform Summary. 2. Information regarding the platform’s condition and readiness to begin P&A work. Four years were required to get Spurr platform in a condition that can support the P&A campaign. a. Are the cranes and work surfaces and helideck on Baker and Dillon ready to begin P&A next year? The cranes and helidecks on both platforms are operational. b. Are inspections needed to confirm their status? No additional Integrity inspections are needed. 3. The risk assessment for the 3 platforms that informs Hilcorp’s proposed P&A schedule. See attached Platform Summary. The well‐risk summary is based on well integrity, surface pressures, gas or oil well, and known intervention issues. This is summarized as follows from highest to lowest risk: Dillon, Baker, Spurr. 4. Is there potential undeveloped hydrocarbon resources that could be accessed from Baker or Dillon platforms? If so, could new drilling targets be drilled from the existing Baker and Dillon platforms, even if the existing wells are P&A’d? Yes. These resources could be drilled from the open well slots left after P&A of the other wells from either platform ‐ pending economic evaluation. 5. Explain how the subsea pipelines have played into Hilcorp’s decision to abandon Baker and Dillon platforms? See attached Platform Summary for pipeline information. While pipeline status is a factor in deciding which platforms to pursue hydrocarbon production from, it is certainly not the only factor. Several re‐ start projects at Baker have been proposed over the years however none were sufficiently economically viable. Platform facility work, platform Integrity work, platform camps, cost of manning a platform, reservoir status, well work, as well as pipeline status are all significant factors. If the AOGCC approves Hilcorp’s proposed CIO P&A plan, Hilcorp will be required to submit Suspension renewal Sundries for all the wells on Spurr platform.  The Spurr Suspension renewal sundries will be conditional on work progressing annually on the P&A of Baker and Dillon. Understood.  Work will be required in 2022 on wells SPR‐05RD2 and SPR‐07 to meet the Suspended Well regulations in 20 AAC 25.110. We would like to discuss the scope of the work AOGCC would like done. Ideally, cementing P&A operations on Spurr would be in one campaign to fully P&A all of the wells in a future year as proposed earlier. This is more efficient, lowers the risk of the program, and obviously is more cost‐effective. However, we can address wellhead/gauge issues on these wells in 2022 without mobilizing heavy wellwork equipment to the platform. Please let us know in advance of the meeting if there is further detail needed by Commissioners to inform your decision. Thanks and Best Regards, Aras Worthington Hilcorp Alaska LLC Senior Technical Advisor for Alaska Operations, PE Aras.worthington@hilcorp.com 907‐564‐4763 907‐440‐7692 mobile From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, January 6, 2022 9:49 AM To: Aras Worthington <Aras.Worthington@hilcorp.com> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: [EXTERNAL] RE: CIO P&A Plan for 2022 4 Aras, Commissioners are open to the idea of rearranging the order of the CIO P&A program, but would like to meet with Hilcorp to discuss the rationale. I’ll set up a meeting next week, but in advance of the meeting, please submit the following information to help make a decision: 1. Information on the structural integrity of each of the 3 platforms. 2. Information regarding the platform’s condition and readiness to begin P&A work. Four years were required to get Spurr platform in a condition that can support the P&A campaign. a. Are the cranes and work surfaces and helideck on Baker and Dillon ready to begin P&A next year? b. Are inspections needed to confirm their status? 3. The risk assessment for the 3 platforms that informs Hilcorp’s proposed P&A schedule. 4. Is there potential undeveloped hydrocarbon resources that could be accessed from Baker or Dillon platforms? If so, could new drilling targets be drilled from the existing Baker and Dillon platforms, even if the existing wells are P&A’d? 5. Explain how the subsea pipelines have played into Hilcorp’s decision to abandon Baker and Dillon platforms? If the AOGCC approves Hilcorp’s proposed CIO P&A plan, Hilcorp will be required to submit Suspension renewal Sundries for all the wells on Spurr platform.  The Spurr Suspension renewal sundries will be conditional on work progressing annually on the P&A of Baker and Dillon.  Work will be required in 2022 on wells SPR‐05RD2 and SPR‐07 to meet the Suspended Well regulations in 20 AAC 25.110. Let me know how much time you need to prepare for this meeting and then I’ll send out an invite. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Aras Worthington <Aras.Worthington@hilcorp.com> Sent: Thursday, December 30, 2021 10:32 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Vanessa Hughes <vhughes@hilcorp.com>; Dan Marlowe <dmarlowe@hilcorp.com>; Chad Helgeson <chelgeson@hilcorp.com>; Josh Allely ‐ (C) <Josh.Allely@hilcorp.com> Subject: CIO P&A Plan for 2022 Bryan, As you are aware work has been ongoing to complete the abandonment work on the Spurr platform. Thus far we have largely stuck to our timeline, albeit one year behind schedule due to unforeseen issues with the unit crane. To date we have completed all the major objectives through original planned activity for 2020 and are now in a position where we could proceed with the downhole work. Hilcorp has risk‐assessed the idle platforms and wells in the Cook Inlet Offshore asset (Baker, Dillon, Spark, and Spurr platforms). These risk assessments indicated that the Dillon wells were the highest risk in that group. The main reason CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 5 for the Dillon wells being higher risk than Spurr is that most of the Dillon wells do not have any cement plugs in them, whereas all of the Spurr wells do have at least one cement plug between the reservoir and surface. Hilcorp therefore proposes to shift our P&A focus from the Spurr platform to the Dillon platform and plan to fully P&A all of the wells on Dillon in 2022. Hilcorp plans to have funding available for that purpose. If for some unknown operational reason the funding cannot be used on Dillon, then Hilcorp will use that funding to complete P&As on the Baker platform. We say this only to make clear that we are committed to having a platform P&A campaign in the Cook Inlet Offshore asset in 2022 and make good on progressing well P&As. Hilcorp proposes the following year‐by‐year P&A campaigns: 2022: CI‐17589 and Dillon Wells 2023: Baker Wells 2024: Spurr Wells Whether it be Dillon, Baker, or Spurr, Hilcorp is committed to dedicating resources to keep the P&A campaign going until the wells on the aforementioned platforms have been fully abandoned. Thanks for your consideration. Aras Worthington Hilcorp Alaska LLC Senior Technical Advisor for Alaska Operations, PE Aras.worthington@hilcorp.com 907‐564‐4763 907‐440‐7692 mobile The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. 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If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. [10:28 AM] Weerasinghe, Chalinda D (DNR) A couple of questions please: From the testimony presented, it is my understanding that the uneconomic nature of production at Dillon, Baker and Spur is not due to diminished economic resource (end of field life), but mainly due to the cost environment present. Would this be a fair statement? What is the likelihood of finding/exploring unproven resources that might be accessible from those platforms?