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Home My WebLink AboutO 196Other Order 196 Docket Number: OTH-22-028 1. August 18, 2022 AOGCC letter to CPAI re: Drillsite 2P P&A plan 2. September 29, 2022 Notice of public hearing, email list, bulk mail list, affidavit 3. January 19, 2023 Hearing transcript, CPAI presentation 4. April 25, 2023 CPAI request for reconsideration STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: KRU Drillsite 2P Well Plugging and Abandonment Plan ) ) ) ) ) ) ) ) ) ) Docket Number: OTH-22-027 Order on Reconsideration of Other Order 196 ConocoPhillips Alaska, Inc. Kuparuk River Unit Meltwater Oil Pool May 3, 2023 ORDER ON RECONSIDERATION On April 25, 2023, the Alaska Oil and Gas Conservation Commission (AOGCC) received a letter from ConocoPhillips Alaska Inc. (CPAI) “request[ing] clarification” of Other Order 196 which was issued on April 6, 2023. Specifically, CPAI requests modification of orders 2 and 3 of Other Order 196. The AOGCC is treating the request as an application for reconsideration pursuant to AS 31.05.080(a). The AOGCC has determined that Other Order 196 will not be modified at this time. The AOGCC will consider the use of new approaches or technologies as outlined in CPAI’s April 25, 2023 letter via the sundry process. The application for reconsideration is DENIED. DONE at Anchorage, Alaska and dated May 3, 2023 Brett W. Huber, Sr. Jessie L. Chmielowski Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE This order on reconsideration is the FINAL order of the AOGCC. It may be appealed to superior court. Any appeal MUST be filed within 33 days after the date on which the AOGCC mails this order, OR 30 days if the AOGCC otherwise distributes this order. 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: 2023.05.03 09:04:53 -08'00' Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.03 09:06:11 -08'00' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West Seventh Avenue Anchorage, Alaska 99501 Re: KRU Drillsite 2P Well Plugging and Abandonment Plan ) ) ) ) ) ) ) ) ) Docket Number: OTH-22-027 Other Order 196 ConocoPhillips Alaska, Inc. Kuparuk River Unit Meltwater Oil Pool April 6, 2023 IT APPEARING THAT: 1. ConocoPhillips Alaska, Inc. (CPAI), operator of the Kuparuk River Unit (KRU) Meltwater Oil Pool (MOP), submitted Applications for Sundry Approval for well work to permanently plug and abandon (P&A) all wells on Drillsite 2P (DS-2P). CPAI’s proposed operations plan for the P&A of the wells on DS-2P must comply with both the well plugging requirements and casing and cementing requirements per 20 AAC 25.112 and 20 AAC 25.030. Due to concerns regarding loss of confinement and in the interest of the public, a public hearing was required for the Alaska Oil and Gas Conservation Commission (AOGCC) to consider whether CPAI’s proposed P&A operations would comply with applicable AOGCC regulations. Additionally, CPAI needed to demonstrate that the abandonment of DS-2P does not result in waste of the resource. 2. Pursuant to 20 AAC 25.540, the AOGCC on its own motion scheduled a public hearing for December 8, 2022. The purpose of the hearing was to receive testimony on the P&A of the wells on DS-2P. On October 3, 2022, the AOGCC published notice of the hearing on the State of Alaska’s Online Public Notice website, on the AOGCC’s website, electronically transmitted the notice to all persons on the AOGCC’s email distribution list, and mailed printed copies of the notice to all persons on the AOGCC’s mailing distribution list. On October 5, 2022 the AOGCC published the notice in the Anchorage Daily News. At the December 8, 2022 hearing, it was announced that the hearing would be rescheduled until January 19, 2023. 3. The AOGCC held the public hearing on January 19, 2023. Testimony was received from CPAI. No members of the public provided testimony at the hearing nor provided written comment. Other Order 196 April 6, 2023 Page 2 of 6 4. Additional written comment was received from CPAI on January 20, 2023 to clarify a response to a question raised by the AOGCC at the public hearing. This comment was included in the record. 5. CPAI’s proposed operations plans, the hearing record, and AOGCC’s public records provide sufficient information to make an informed decision. FINDINGS: 1. MOP is part of the KRU but lies 10 miles southwest of the main portion of the KRU. This pool was discovered and delineated in 2000 by three wells: Meltwater North 2, Meltwater North 1, and Meltwater North 2A, which are all now P&A’d. The pool consists of several laterally discontinuous, turbidite channels and lobes that form a compartmentalized reservoir, often with poor interwell communication between injectors and producers. 2. The AOGCC issued Area Injection Order (AIO) 21 for the MOP on August 1, 2001, authorizing the underground injection of fluids for enhanced oil recovery. 3. CPAI developed the MOP from 2001 to 2004 using 23 wells drilled from DS-2P. Four of these wells were previously P&A’d, leaving 11 producers and 8 injectors that are currently shut in and remain to be P&A’d. 4. During and after development, elevated outer annulus (OA) pressures were observed in 10 wells as the result of a reservoir loss-of-containment event in which miscible injectant (MI) migrated from the approved injection interval. CPAI believes this was likely caused by over- pressuring of reservoir compartments through injection above fracture gradient, which compromised the top seal. 5. After injection activities in the MOP resulted in loss-of-containment allowing injected fluids to migrate into shallower strata, the AOGCC revoked AIO 21 and associated administrative actions and replaced them with AIO 21A on January 29, 2013. 6. On October 8, 2015, AIO 21A and all associated administrative approvals were revoked and replaced by AIO 21B. Geologic and production data analyses at that time indicated AIO 21A did not accurately describe the MOP and lack of confinement of injected fluids. 7. Conclusion 3 of AIO 21B states: “CPAI estimates that 25- 30 percent of the fluids injected into the MOP cannot be accounted for in the reservoir material balance and are suspected to have escaped reservoir containment.” Other Order 196 April 6, 2023 Page 3 of 6 8. MOP was shut in September 2021. Based on analysis presented by CPAI, DS-2P is uneconomic to produce due to high water-cut (greater than 98 percent) and estimated production backout from pipeline hydraulics, facility constraints, and water injection pump- horsepower allocated to Meltwater that could have been used more effectively to support production elsewhere. CPAI testified that the above factors result in negative net production from MOP. 9. At Meltwater, fluids have been evacuated from all pipelines and all pipelines are currently sealed. Surface infrastructure is disconnected from production lines. All safety equipment is connected and will remain operational until all Meltwater wells are P&A’d. 10. On November 16, 2021 and July 19, 2022, CPAI presented to the AOGCC proposed operations plans for full abandonment of all DS-2P wells. CPAI’s proposal included plans to P&A the 19 remaining unplugged wells on DS-2P by setting three cement plugs in each well: (1) one in the OA, (2) one across the reservoir section, and (3) one across the tubing and inner annulus. CPAI proposes to P&A one well (2P-447) via rig workover in which the tubing will be removed. In one well (2P-406), CPAI proposes to place cement in the OA by perforating and circulating. In the remaining 17 wells, CPAI proposes to place cement plugs in the OA via a down squeeze method1. 11. It is possible that performing an OA down squeeze could potentially fracture the confining layer and create a conduit to surface. However, CPAI does not believe this will occur. 12. In the 17 DS-2P wells in which an OA down squeeze is proposed, CPAI did not propose a method to verify the placement and quality of the OA cement plugs other than pressure testing. 13. Additionally, for those same 17 wells, in the event that the plugging operation is unsuccessful, CPAI did not propose a method to remediate or repair the wells to ensure an adequate OA plug. 14. AOGCC regulation 20 AAC 25.112 governs the P&A of wells. CPAI states that it is not seeking waivers or variances from 20 AAC 25.112. 15. AOGCC regulation 20 AAC 25.030 governs the casing and cementing of wells during drilling and completion. Included in this regulation are requirements to confine fluids to the wellbore 1 A procedure for placing cement (or other fluids) in the outer annulus (OA) of a well by pumping cement into the OA from surface and applying pump pressure to force the cement down the OA and out from the bottom of the outer casing string. Once cement exits the casing, its continued flow path and placement is unpredictable. Other Order 196 April 6, 2023 Page 4 of 6 and prevent migration of fluids from one stratum to another. Further, if zonal isolation is required but not established, the AOGCC will require a cement quality log or other method to demonstrate isolation of the zone. CPAI did not address whether it is seeking waivers or variances from 20 AAC 25.030. 16. CPAI’s interpretation of 4D seismic data acquired across the Meltwater area identifies three northwest-trending lineaments within the development area. These lineaments are aligned with the interpreted maximum horizontal stress direction in the area. The upper mappable extent of these lineaments lies about 200 vertical feet below CPAI’s C-37 marker that coincides with the base of the Schrader Bluff Formation (Schrader Bluff). The upper mappable limit of the lineaments is based on seismic data quality, and the noise level in the data above that depth leads the data to be uninterpretable, so it is possible that the lineaments, especially the central lineament, could extend above that depth. However, CPAI’s representative testified that although the central lineament could extend higher, it is unlikely to extend significantly higher than the upper mappable limit. 17. CPAI’s C-80 marker, which lies about 1,100 vertical feet shallower than the C-37 marker, separates the middle and upper Schrader Bluff. 18. During the public hearing, CPAI’s representative testified that they believe the laterally continuous, sandy section near the C-80 marker is the best candidate for harboring minor amounts of residual gas that migrated out of the MOP due to loss of containment early in field history. CPAI believes the MI migrated from the MOP reservoir into the C-80 sands; however, no evidence or data was presented to prove the hypothesis that the C-80 sands are the only place where the MI migrated. 19. At Meltwater, surface casing is typically set between the base of the West Sak interval (within the upper Schrader Bluff) and the C-80 marker. Intervals of laterally continuous marine shales are present within the lower portion of the West Sak and upward to the permafrost base, which lies about 1,100 vertical feet below mean sea level in this area. Correlative shales in the Kuparuk River Unit area have formation integrity and leak-off test data of up to 0.84 psi/ft (about 16.2 ppg equivalent mud weight). CPAI believes these shales are likely vertical barriers to fluid movement behind casing and below permafrost. 20. The initial estimate of recoverable oil from the MOP was 47.5 million stock tank barrels of oil (MMSTBO). Development of the pool showed it to be more compartmentalized than initially Other Order 196 April 6, 2023 Page 5 of 6 thought, which limited the effectiveness of the enhanced oil recovery (EOR) process, and recovery estimates were reduced to 20.9 MMSTBO. 21. To date 20.2 MMSTBO has been recovered from the pool. The 0.7 MMSTBO difference between the actual production and the estimated ultimate recovery represents approximately a 3% difference. CONCLUSIONS: 1. MOP is currently shut in and has been determined by the operator to be uneconomic to produce from its compartmentalized reservoir with often poor interwell communication. Nineteen wells drilled into this pool remain to be P&A’d. 2. The MOP has reached the end of its productive life and has recovered as much oil as could feasibly be expected. As such, it is appropriate to permanently P&A all wells in the pool. 3. During the casing and cementing of these 19 DS-2P wells, zonal isolation was not established as required by 20 AAC 25.030(a)(3). MI was not confined to the approved injection interval, likely due to over-pressuring of reservoir compartments through injection above fracture gradient, and it migrated vertically into other strata. The present distribution of that migrated MI is not completely known. 4. During the P&A operations on the DS-2P wells, the requirements of 20 AAC 25.112 and 20 AAC 25.030 both apply. CPAI is not seeking waivers or variances from 20 AAC 25.112. However, since the requirements of 20 AAC 25.030 also apply to the P&A of DS-2P wells, CPAI’s proposed operations plan would require waivers or variances to 20 AAC 25.030 relating to the lack of required zonal isolation. 5. CPAI’s proposed method to place reservoir plugs and tubing and inner annulus plugs in all 19 wells meets AOGCC regulations. 6. CPAI’s proposal to place cement plugs in the OA via a down squeeze method on DS-2P wells, however, does not comply with 20 AAC 25.030 and a waiver would not be appropriate because, due to loss of containment of MI and migration of fluids into shallower strata, the placement and quality of the cement plug in the OA must be demonstrated. 7. Thus, for the OA plugs, because zonal isolation is required but was not established, the AOGCC will require a cement quality log or other method to demonstrate placement and quality of the cement plug and isolation of the hydrocarbon-bearing intervals per 20 AAC Other Order 196 April 6, 2023 Page 6 of 6 25.030(b)(5). Zonal isolation using the OA down squeeze method cannot be verified without decompleting the well and obtaining a cement quality log. 8. Without verification of zonal isolation, the P&A operations cannot be completed according to regulations. 9. P&A operations may require pressure monitoring at the surface for a period of time to be determined by the AOGCC and outlined in the approvals of the Applications for Sundry Approval (Form 10-403). NOW, THEREFORE IT IS ORDERED THAT: 1. P&A operations on DS-2P wells must comply with 20 AAC 25.112 and 20 AAC 25.030. 2. CPAI’s proposal to place cement plugs in the OA via a down squeeze method in the DS-2P wells is denied. 3. Zonal isolation and verification with a cement quality log is required by the AOGCC. 4. P&A operations on DS-2P will be approved by the AOGCC through the Application for Sundry Approval (Form 10-403). DONE at Anchorage, Alaska and dated April 6, 2023 Brett W. Huber, Sr. Jessie L. Chmielowski Chair, Commissioner Commissioner RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.04.05 12:27:17 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2023.04.05 15:47:44 -05'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:Other Order 196 (CPAI) Date:Thursday, April 6, 2023 9:21:00 AM Attachments:other196.pdf KRU Drillsite 2P Well Plugging and Abandonment Plan Samantha Carlisle 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 4/6/23 4 ConocoPhllipsi April 25, 2023 Brett W. Huber, Sr. Chair, Commissioner Alaska Oil and Gas Conservation Comm'n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Gregory Wilson Commissioner Alaska Oil and Gas Conservation Comm'n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 VIA E-MAIL(samantha.carlisle(c�alaska.gov) Re: Docket Number OTH-22-027 Other Order 196 Request for Clarification Tyler Senden CTD / RWO Engineering Director 700 G Street, ATO 676 Anchorage, AK 99510 (907) 265-1544 (office) R.Tyler.Senden@conocophillips.com Jessie Chmielowski Commissioner Alaska Oil and Gas Conservation Comm'n 333 West Seventh Avenue, Suite 100 Anchorage, Alaska 99501-3572 Commissioners Huber, Chmielowski, and Wilson: On April 6, 2023, the Alaska Oil and Gas Conservation Commission (AOGCC) issued Other Order 196 regarding ConocoPhillips Alaska, Inc. (CPAI) plans to plug and abandon wells at Kuparuk River Unit (KRU) drillsite 2P (DS-21P). CPAI respectfully requests clarification of determinations 2 and 3 of Other Order 196, set forth below: 2. CPAI's proposal to place cement plugs in the OA via a down squeeze method in the DS- 2P wells is denied. 3. Zonal isolation and verification with a cement quality log is required by the AOGCC. On April 18, 2023, CPAI met with AOGCC technical staff. Regarding determination 2, AOGCC staff advised that down squeezes potentially could be approved at Meltwater to address zonal isolation, if CPAI is able to log cement quality. Such logs are not typically done, but CPAI is exploring potential technical solutions to do this. Regarding determination 3, we discussed with AOGCC staff one alternative P&A method could be a full bore plug. If this method were used, the plug would be tagged and pressure tested but not logged (logging would not be possible). In light of this conversation with AOGCC staff, our understanding is that determinations 2 and 3 could be clarified as follows: 2. CPAI's proposal to place cement plugs in the OA via a down squeeze method in the DS- 2P wells is denied as a method to address zonal isolation,' unless CPAI is able to provide cement quality logs or other data demonstrating cement placement and quality (beyond pressure testing, which CPAI will do for any down squeeze OA plug). 3. Zonal isolation and verification with a cement quality log or other data demonstrating cement placement and quality (for example, a tag and pressure test, in the case of a full bore plug) is required by the AOGCC. If our above understandings are correct, we respectfully request that the AOGCC clarify Other Order 196 as shown above. These clarifications will greatly assist us in our planning and ongoing work with AOGCC staff on DS-2P well abandonment. CPAI also wishes to provide one clarification from the hearing. Finding 13 of Order 196 states that in the event the OA down squeeze was unsuccessful, "CPAI did not propose a method to remediate or repair the wells to ensure an adequate OA plug." At the hearing, CPAI stated that if pressure were detected at surface after the plugging operation, CPAI would "have to put a rig on that particular well." Tr. 45:14-17. By this statement, CPAI intended to indicate that well remediation would certainly occur. However, the AOGCC is correct that CPAI did not propose a single method for remediation, which would depend on the circumstances of the particular well. ince ly, Tyler Sen RWO / CTD Engineering Director ConocoPhillips Alaska, Inc. 1 CPAI understands that the AOGCC will still require an OA surface plug in all wells, per 20 AAC 25.112, which would typically be set via down squeeze. 2 3 AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 the Abandonment of the ) Kuparuk River Unit Drillsite 2P also ) known as Meltwater by ConocoPhillips ) Alaska. ) _________________________________________) Docket No.: OTH-22-027 PUBLIC HEARING January 19, 2023 10:00 o'clock a.m. BEFORE: Jessie Chmielowski, Commissioner Brett Huber, Commissioner and Chair AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 Commissioner Huber 03 3 Testimony by Mr. Senden 07 4 Testimony by Mr. Perfetta 09 5 Testimony by Mr. Addas 18 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 CHAIR HUBER: Good morning. I'll call this 4 hearing to order. It's 10:00 a.m. on January 19th, 5 2023. This is a public hearing continued from the 6 December 8, 2022, docket number OTH-22-027 to address 7 the abandonment of the Kuparuk River Unit, Drillsite 8 2P, also known as Meltwater. I'm Commissioner and 9 Chair Brett Huber. With me is Commissioner Jessie 10 Chmielowski. Today's hearing, thank you for being here 11 in person today, is at our office at 333 West Seventh 12 Avenue. 13 We're also participating in this hearing via 14 Teams so let me remind you if you're online via Teams 15 please mute yourself if you're not participating and 16 we'll try to keep background noise to a minimum. 17 If you require any special accommodation for 18 today's hearing you can contact Samantha Carlisle in 19 our office. She can be reached at 907-793-1223 or she 20 will also be monitoring the Teams chat. So if you need 21 something from Samantha please feel free. 22 Computer Matrix will be recording the hearing 23 today. Upon completion and preparation of the 24 transcript if you want a copy it can be obtained by 25 contacting Computer Matrix. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 This hearing is being held in accordance today 2 with Alaska Statute 44.62 and 20 AAC 25.540 of the 3 Administration Code. 4 The notice of hearing was published on the 5 State of Alaska Online Notices website as well as the 6 AOGCC website and was sent through the AOGCC Email List 7 Serv on October 3. The AOGCC also published the notice 8 in the Anchorage Daily News on October 5. 9 To date the AOGCC has not received any public 10 comment on the matter. 11 Before asking you all from Conoco to start I'd 12 like to ask my fellow Commissioner if she has any 13 initial questions or comments for the record. 14 COMMISSIONER CHMIELOWSKI: I don't. Thank you. 15 CHAIR HUBER: Representatives from 16 ConocoPhillips are you ready to make your presentation? 17 MR. SENDEN: Yes. 18 CHAIR HUBER: Awesome. Please keep in mind 19 that you speak into the microphone. Also remember to 20 reference your slides if you would so somebody 21 following along or looking at the public record in the 22 future can follow along with the slides. 23 Do any of you wish to be recognized as experts 24 in your testimony today. 25 MR. SENDEN: Yes. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 CHAIR HUBER: Go ahead and state your 2 credentials for us, please. 3 MR. SENDEN: Good morning. I'm -- my name is 4 Ty Senden. I graduated from UAF with a bachelor's of 5 science in civil engineering. I worked as a field 6 engineer from 1995 to 2001 before being hired by 7 Phillips Petroleum and later Conoco Alaska. Since 2003 8 I've been a wells engineer or engineering supervisor 9 working on wells around the entire state of Alaska from 10 exploration wells out west of Alpine, as far east as 11 our West Michelson well and as far south as Lower Cook 12 Inlet. All of my work has been for -- in Alaska for 27 13 years. 14 I would like to be recognized as an expert in 15 well integrity and intervention. 16 COMMISSIONER CHMIELOWSKI: I have no 17 objections. 18 CHAIR HUBER: Without objection you'll be 19 recognized as an expert. 20 Additional experts? 21 MR. PERFETTA: Yes. My name is Patrick 22 Perfetta, the project geologist for Meltwater. I'd 23 like to be recognized as an expert in geology. 24 I earned a bachelor of science degree in 25 geology from Indiana University of Pennsylvania and a AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 master's degree in geology from the University of 2 Missouri Columbia. I have approximately 25 years of 3 industry experience all with ConocoPhillips and its 4 heritage companies. I've had roles in new ventures 5 exploration to field development, technical oversight 6 and lead roles and I have approximately 15 years of 7 experience in Alaska. 8 COMMISSIONER CHMIELOWSKI: Thank you. I have 9 no objections. 10 CHAIR HUBER: Without objection you'll be 11 recognized as an expert. 12 Thank you. 13 MR. ADDAS: Good morning. My name is Sayeed 14 Addas, spelled S-A-Y-E-E-D A-D-D-A-S. I'm the 15 reservoir engineer for the Meltwater field for 16 ConocoPhillips Alaska. I'd like to be recognized as an 17 expert in chemical engineering. 18 I graduated with a bachelor's of technology in 19 chemical engineering in 2003 from the Indian Institute 20 of Technology and in 2008 I received my Ph.D in 21 chemical engineering from the University of Minnesota 22 Twin Cities. I worked as an research engineer and 23 scientist with the Dowl Chemical Company from 2008 to 24 2013 where I worked on enhanced oil recovery 25 technology. I joined ConocoPhillips in 2013 in the AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 global technology function where I worked on multiple 2 projects with ConocoPhillips Alaska mainly 3 (indiscernible). I moved to Alaska in summer of 2019 4 and since then I've been the reservoir engineer for 5 Meltwater. 6 COMMISSIONER CHMIELOWSKI: I have no 7 objections. 8 CHAIR HUBER: Again without objection you'll be 9 recognized as an expert. 10 Thank you all for that. And I will go on to 11 getting ready for your testimony. We'll begin by 12 swearing in so anybody's who's going to provide 13 testimony raise their right hand. 14 (Oath administered) 15 IN UNISON: Yes. 16 CHAIR HUBER: Thank you. Who's going to lead 17 on the presentation. 18 MR. SENDEN: I will. 19 CHAIR HUBER: Excellent. Please proceed. 20 TY SENDEN 21 having been first duly sworn under oath, called as a 22 witness on behalf of ConocoPhillips Alaska, testified 23 as follows: 24 MR. SENDEN: Good morning, Commissioner 25 Chmielowski and Chair Huber. My name is Ty Senden, I'm AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 one of the team members of the Meltwater abandonment 2 project. On behalf of ConocoPhillips Alaska and my 3 colleagues, Pat Perfetta and Sayeed Addas we are here 4 to testify as expert witness as it relates to the 5 plugging and abandonment of the Meltwater field. 6 I'll be brief in my initial comments. Thank 7 you to the Commissioners for granting us on behalf of 8 ConocoPhillips Alaska the opportunity to speak to you 9 today about the Meltwater plugging and abandonment 10 plan. We would also like to recognize the AOGCC Staff 11 who have provided feedback on numerous preliminary 12 meetings and sundry submission. 13 This is slide two, an acronyms reference list. 14 Please if you have any questions -- you'll see these 15 throughout our presentation. If you have any questions 16 or need clarification please let us know. 17 Slide three is our objective and agenda slide. 18 During this hearing and specifically slide pack 19 presented today we will show one, continued operation 20 of Meltwater drillsite will back out more oil in 21 production than the drillsite currently produces, how 22 the frack gradient in the confining layer exceeds that 23 of the C80 sands below providing a sound barrier and 24 that our proposed OA downsqueeze method does meet all 25 the regulations specific 20 AAC 25.112. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 Any questions on slide three? 2 (No comments) 3 PAT PERFETTA 4 having been first previously sworn under oath, called 5 as a witness on behalf of ConocoPhillips Alaska, 6 testified as follows: 7 MR. PERFETTA: Okay. This is Pat Perfetta, 8 we're on slide four. I'll give a brief field overview 9 and geologic background. 10 Okay. Moving to slide five. So this is a high 11 level introduction to the location and well history of 12 Meltwater field. Meltwater or drillsite 2P is the 13 southern most satellite field of the Kuparuk River 14 Unit. It's located approximately 10 miles south of 15 drillsite 2N which is one of the Tarn field drillsites. 16 You can see this on the small scale inset map in the 17 lower left of the slide. The field was discovered by 18 the Meltwater N2 well shown on the larger scale map as 19 the yellow star. This well was spud in January of 20 2000. This was immediately followed by the Meltwater 21 N1 well that same year shown as the red star on the 22 map. All wells are currently shut-in at the field, but 23 over field life after the Meltwater N1 and N2 wells 24 were drilled 23 development wells were drilled, four 25 boreholes have been plugged and abandoned and there are AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 currently 11 wells designated as producers and eight 2 wells designated as injectors. Therefore there are 19 3 wells in need of P&A as part of field abandonment. 4 If there are no questions on this slide I'll 5 proceed to the -- a brief geologic overview. 6 (No comments) 7 MR. PERFETTA: Okay. Slide six. As mentioned 8 this slide will cover a geologic overview of Meltwater 9 field and provide context for what will be shared 10 during the remainder of the presentation. First I'll 11 describe the type log of the Meltwater N2 well which is 12 shown on the left side of the slide. Track one is a 13 display of gamma ray and caliper. This is followed by 14 depth reference tracks in TVD subsea and measured 15 depth. Track three immediately right of the depth 16 track is a resistivity display of shallow, medium and 17 deep resistivity. Track four contains density neutron 18 curves. To the left of the log display are key 19 geologic markers and descriptors, to the right of the 20 log display are geologic formations associated with the 21 regional stratigraphy. On the upper right of the slide 22 is an inset well spider map. This includes additional 23 reference information relating to stratigraphy of the 24 reservoir overburden and pertinent geologic features. 25 I'll talk to the details of that in a moment. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 Circling back to the type log of the Meltwater 2 N2, this is located -- the Meltwater N2 is shown on the 3 yellow star on the map on the right. I'd first like to 4 point out the green shaded box at the bottom of the log 5 display. This box highlights the Meltwater oil pool or 6 Bermuda reservoir interval. The Bermuda reservoir is 7 part of the original CD formation. It was deposited as 8 part of the fill sequence of a slope canyon system 9 primarily as levied turbidite channels with some minor 10 turbidite load deposition. A geoseismic section is 11 shown on the bottom center of the slide. The location 12 of this section can be seen on the inset map denoted by 13 the line A to A prime. The geoseismic section is shown 14 in order to schematically demonstrate the 15 compartmentalized nature of the Meltwater reservoir 16 sand. This is depicted on the inset cross-section 17 which shows laterally discontinuous sand bodies between 18 wells. There's are also likely baffles present which 19 are internal to the sands that are interpreted to be 20 correlative between wells. This can be seen between 21 wells 2P434 and 2P417 on the left side of the 22 geoseismic section. 23 It was found during early well development that 24 interwell communication between injection and 25 production wells was poor. This was likely related to AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 the depositional architecture of the Bermuda sands. As 2 a result of the poor interwell reservoir communication 3 and early field injection history it is believed that 4 the top seal of the field was compromised. This was 5 likely due to over pressuring compartments within the 6 reservoir in combination with injection above fracture 7 gradient. 8 The field history and description of Meltwater 9 has been reviewed in previous AOGCC hearings relating 10 to Meltwater field. Also previously covered, but to 11 briefly summarize here, there are three lineaments that 12 were detected during 4D seismic interpretation of the 13 field. These lineaments are present at the reservoir 14 level and in the immediate overburden of Meltwater 15 field. The location of these lineaments are shown on 16 the map represented by the gray dash lines and gray 17 shaded polygons. These lineaments are aligned with the 18 interpreted maximum horizontal stress in the area and 19 are centered on original field injection wells. The 20 upward vertical mappable extent of these lineaments is 21 shown on the left side of the log display. This depth 22 is approximately 200 feet below the C37 marker for the 23 central lineament and slightly deeper for the other two 24 lineaments. 25 For reference the green Xs on the map represent AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 the well intersections of the top and base Bermuda 2 reservoir. The purpose Xs on the map represent where 3 the wellbores intersect the C37 marker. The breach of 4 the overburden is believed to have allowed a small 5 amount of injected gas to exit Meltwater oil pool and 6 enter the overburden potentially interacting with open 7 intermediate casing annuli. In general the Meltwater 8 field overburden section between surface casing set 9 depth and the top of the Bermuda reservoir interval 10 consists predominantly of a shale prone section with 11 few thin very discontinuous sands. The exception to 12 this is the section immediately below and above the C80 13 marker. The C80 marker is shown by the blue dashed 14 line on the log display and corresponding blue Xs on 15 the spider map display. It is interpreted that the 16 sandy section near the C80 marker is the best candidate 17 for harboring minor amounts of residual gas that have 18 migrated out of the Bermuda reservoir due to loss of 19 containment early in field history. 20 Unless there are any questions on this geologic 21 background I'll move to slide seven. 22 COMMISSIONER CHMIELOWSKI: I have some 23 questions. I'd like to talk about the three fractures 24 you mention on that top right part of the slide. Now 25 you say that those are imaged up to 1,700 feet or about AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 what, you said 200 feet of the C37? 2 MR. PERFETTA: Yes. 3 COMMISSIONER CHMIELOWSKI: Now how..... 4 MR. PERFETTA: About 200 feet below the C37. 5 COMMISSIONER CHMIELOWSKI: .....how is that 6 determined, is that limit based on data quality or you 7 actually have other information to base that on? 8 MR. PERFETTA: That is correct. It's based on 9 the seismic data quality, the noise level in the data 10 above that depth leads them to be uninterpretable. 11 COMMISSIONER CHMIELOWSKI: So they could exist 12 above that depth? 13 MR. PERFETTA: It is possible, especially the 14 central conduit could extend above that depth. 15 COMMISSIONER CHMIELOWSKI: Okay. 16 MR. PERFETTA: However, the east -- the two 17 other conduits die out prior to the noise level in the 18 data being poor. So the likelihood of the central one 19 extending significantly above is unlikely. 20 COMMISSIONER CHMIELOWSKI: Oh, so the central 21 would not, but the two outside ones might? 22 MR. PERFETTA: No, I'm saying the..... 23 COMMISSIONER CHMIELOWSKI: Oh, opposite, yeah. 24 MR. PERFETTA: .....opposite. 25 COMMISSIONER CHMIELOWSKI: Yeah. Okay. Got it. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 CHAIR HUBER: So you're drawing the conclusion 2 that the -- I'm sorry, you're drawing the conclusion 3 that because the other ones end before that noise that 4 the other one likely is..... 5 MR. PERFETTA: Yeah, it -- it could extend 6 higher, but it's unlikely to extend significantly 7 higher. 8 COMMISSIONER CHMIELOWSKI: Okay. 9 CHAIR HUBER: Thank you. 10 MR. PERFETTA: Yeah. 11 COMMISSIONER CHMIELOWSKI: And then did you say 12 the C80 is laterally continuous sand? 13 MR. PERFETTA: Yes. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. PERFETTA: That's correct. 16 COMMISSIONER CHMIELOWSKI: And that's the basis 17 for Conoco determining that that's where out of zone 18 injection went is the laterally continuous sand? 19 MR. PERFETTA: Yes, it's -- it's the most 20 likely spot for harboring the sand. You could have 21 residual gas in inner sands and other places in the 22 overburden, but that's the most laterally continuous 23 sandy interval. 24 COMMISSIONER CHMIELOWSKI: So the -- Conoco's 25 interpretation is just based on what's most likely, AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 there's really no data to prove where the gas went? 2 MR. PERFETTA: That's correct. 3 COMMISSIONER CHMIELOWSKI: Okay. Thank you. 4 MR. PERFETTA: So the next slide will focus on 5 the shallow overburden and this is the area immediately 6 above and below the C80 marker and upwards into the 7 base of the permafrost. On this slide is a 8 stratigraphic well log cross-section. The datum of 9 this cross-section is the C80 marker. From left to 10 right in each well are gamma ray derived via shale in 11 the left most track followed by a subsea TVD and 12 measured depth reference. And then to the right of 13 that are shallow, medium and deep resistivity and then 14 density of neutron curves on the right-hand track in 15 each of the wells. 16 There are four wells in this cross-section. 17 The location of the wells are shown by the yellow dots 18 in the inset map and the yellow dots are shown where 19 the wells intersect the C80 marker. It's designated as 20 line B to B prime on the map. The wells for this 21 section were chosen because they each drill in a 22 different azimuth from the pad. This was done in order 23 to show the consistency of this portion of the 24 overburden section between the Meltwater field wells. 25 The location of geologic markers are shown on the AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 right-hand side of the cross section display. For 2 reference surface casing was typically set in Meltwater 3 field between the base West Sak and the C80 marker. 4 This is shown by the black dashed lines on each of the 5 wells, that's where the surface casing was set in 6 these. As previously mentioned the interval 7 immediately above and then below the C80 marker 8 contains laterally continuous sand prone intervals as 9 seen in the lithology descriptions of drill cuttings 10 and from petrophysical interpretation. This interval 11 is highlighted in yellow on the cross-section. 12 Behind surface casing cement, between the base 13 of permafrost and the C80 is the West Sak interval. 14 Within the West Sak are a series of laterally 15 continuous marine shales highlighted by the gray 16 intervals on the log display. No strength data for 17 these shales, either FIT or LOT is available for 18 Meltwater field proper however correlative shales with 19 similar properties to the north Kuparuk field have 20 formation integrity and leak off test data of up to 0.4 21 psi per foot. Therefore these shales are likely 22 vertical barriers to fluid movement behind surface 23 casing and below the base of permafrost which is 24 highlight in the blue shading. 25 Unless there are any further questions I'll AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 turn it over to Sayeed for a field production injection 2 history. 3 (No comments) 4 SAYEED ADDAS 5 having been first previously sworn under oath, called 6 as a witness on behalf of ConocoPhillips Alaska, 7 testified as follows on: 8 MR. ADDAS: Okay. So we are on slide eight. 9 In the next few slides I will provide a brief overview 10 of Meltwater production history and recap major events 11 that ultimately led to the abandonment decision for 12 Meltwater. At this time we are not seeking any AOGCC 13 approval related to Meltwater abandonment however we 14 are seeking the AOGCC approval for the P&A sundries and 15 hopefully the subsequent slides and discussion provide 16 additional context for those sundry requests. 17 We're on slide nine. This slide recaps how the 18 recovery (indiscernible) estimation for Meltwater 19 changed over the years. In the beginning the original 20 oil in place estimate for Meltwater was 125 million 21 barrels of oil out of which 52 million barrels was 22 expected to be recovered. That equated to a recovery 23 factor of 41.6 percent. This information was 24 communicated in the pool rules hearing in 2001. This 25 was before first oil was produced from Meltwater and AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 included up site from peripheral development. 2 Once development started wells were drilled to 3 deliberately test the extent of the reservoir. Of 4 these two fringe wells, 2P448 and 2P419 encountered 5 little data. 2P448 found the western extent of the 6 reservoir whereas 2P419 found the southern extent. 7 Another well, 2P422 encountered a water transition 8 zone. All of this information along with the 2008 9 seismic was used to update the net pay map which 10 resulted in an oil in place value of 60 million barrels 11 approximately. This was communicated in the AIO-21 12 amendment hearing in 2012. Based on the field 13 performance a total recovery factor estimate between 30 14 to 35 percent was also provided in the hearing during 15 G&A. Subsequent work was pursued to evaluate 16 development drilling candidates in Meltwater. 17 In the 2015 hearing it was communicated that a 18 further two to 7 million barrels of incremental 19 recovery was possible if development drilling was 20 pursued. Those initiatives did not materialize. At 21 the point of (indiscernible) Meltwater recovery was 22 33.6 percent which is between the 30 to 35 percent 23 recovery factor range communicated during the 2012 24 hearing. Total recovery was 20.3 million barrels of 25 oil. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 The factors that played a key role in oil 2 recovery include injection below parting pressure which 3 started from 2012 as a direct consequence of out of 4 zone injection. This limited (indiscernible) within 5 the field. The other factor is the geological 6 complexity and compartmentalization that was already 7 discussed with limited communication between injector 8 and producer. 9 Any questions from this slide? 10 (No comments) 11 MR. ADDAS: Okay. We're now on slide 10. This 12 slide shows the entire history of Meltwater oil 13 production in the top block, water production in the 14 middle and gas production in the bottom. Meltwater 15 came online in 2001, peak oil production of 16 approximately 12,000 barrels of oil per day was 17 achieved from the field. The field never produced much 18 water, the exception from 2009 to 2012. Primary reason 19 for that water production was because 2P432 which used 20 to be a water injector was converted to a producer. 21 Meltwater produced relatively more gas compared to 22 water in its history. This was primarily because the 23 turbidite loads had better communication with gas 24 compared to water due to the high mobility of gas in 25 the reservoir. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 An important point I want to point out here is 2 the decision in 2012 to reduce sandface injection 3 pressure limit. The effect of that decision can be 4 observed in the oil production trend where a faster 5 decline occurred after that change was implemented. 6 Some other important events are annotated in 7 the block and I'm going to talk about them in the 8 subsequent slide. 9 Any questions from this slide? 10 COMMISSIONER CHMIELOWSKI: So the sandface 11 injection pressure limit is when ConocoPhillips stopped 12 injecting above frack pressure. 13 MR. ADDAS: Yes. 14 COMMISSIONER CHMIELOWSKI: Okay. 15 MR. ADDAS: So now we're on slide 11. This 16 slide shows the injection history in Meltwater. The 17 top block shows the water injection history and the 18 bottom block shows the gas injection history in the 19 reservoir. The maroon color in the gas injection block 20 corresponds to the civil gas injection where the dark 21 yellow color is lean gas injection. We observed that 22 water injection line corroded out in 2009 and water 23 injection was stopped. From here on only one injection 24 pipeline serviced Meltwater. From 2009 until 2019, so 25 for a decade, Meltwater was on continuous gas AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 injection. In 2019 the pipeline was finally converted 2 to water injection. The impact of the decision to 3 reduce injection pressure in 2012 can also be observed 4 in the gas injection gridblock that a reduction of 5 miscible gas injection rate occurred. 6 Any questions on this slide? 7 COMMISSIONER CHMIELOWSKI: Do you know why 8 ConocoPhillips took so long to reinstate water 9 injection? 10 MR. ADDAS: Because the reason was because 11 Conoco believed that gas injection was the most 12 efficient fluid that would recover oil from this 13 reservoir. That perception changed as -- and I will 14 cover that in a subsequent slide, as the gas/oil ratio 15 continued to climb and they continued to back out more 16 and more oil from the field. We will discuss that in 17 the next slide. 18 COMMISSIONER CHMIELOWSKI: Okay. So it was 19 considered good reservoir management practice at the 20 time? 21 MR. ADDAS: Yes. 22 COMMISSIONER CHMIELOWSKI: Okay. 23 MR. ADDAS: We're on slide 12. This slide 24 shows a gas/oil ratio response to the decade long 25 continuous gas injection. The top block shows the AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 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 gas/oil ratio and the bottom block shows the gas 2 injection history again with the same color 3 description. The gas/oil ratio climbed in the 4 reservoir due to continuous gas injection over the 5 years. This led to back out of production from other 6 drill -- from other drillsites elsewhere in CPF2. In 7 the 2018 hearing it was communicated that a shut-in 8 test performed in Meltwater estimated that 13 million 9 standard cubic feet per day of gas production from 10 Meltwater backed out approximately 900 barrels of oil 11 per day from other areas of CPF2. The data clearly 12 showed that Meltwater was on an unsustainable path on 13 continuous gas injection and the decision was taken to 14 convert the field to water injection. Next slide. 15 This is slide 13. In this slide we will focus 16 on the development in Meltwater after the decision to 17 shift to water injection was taken. A concern 18 discussed during the 2018 hearing was the possibility 19 of the 24 inch produced oil line freezing due to low 20 flow. That scenario played out in the winter of 21 2018/2019 when the produced oil line froze and all 22 production from Meltwater was shutdown. The loss of 23 oil production from Meltwater can be observed in this 24 block. The oil production is shown in the top chart, 25 water production in middle and gas production in the AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 24 1 bottom. This also underscored the need to convert the 2 drillsite to water injection. The conversion to water 3 injection occurred in late summer of 2019 after the gas 4 injection line to Meltwater was converted to water 5 service. As a result gas was no longer available in 6 Meltwater including any lift gas for Meltwater wells. 7 In the beginning after the conversion there was still 8 enough gas production from the reservoir and that 9 helped production. However the gas/oil ratio went down 10 as was expected after the conversion to water injection 11 and a couple of wells in 2P was converted to jet pump 12 service to aid in lifting the wells. 13 Overall Meltwater production still continued to 14 trend down. There were periods in late 2020 and early 15 2021 when production struggled to exceed even 200 16 barrels of oil produced from the entire field and at 17 times there was just no oil production. It was evident 18 that production was hurting due to lack of injection 19 support which we will cover in the next slide. Next 20 slide. 21 This is slide 14 which shows Meltwater's 22 injection history in the last few years. After the 23 conversion to water injection in summer of 2019 initial 24 water injection rates was promising. But those rates 25 rapidly declined over the next one year. This decline AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 25 1 in injectivity was due to reservoir fill up. It is 2 worth noting here that this was the first time water 3 was being injected into Meltwater below the parting 4 pressure of the rock and below the sandface pressure 5 limit of 3,400 psi. (Indiscernible) to boost injection 6 with chemicals, but the effect was only temporary. 7 This lack of injectivity can be rationalized by 8 recalling the compartmentalized nature of the Bermuda 9 interval in Meltwater. With water and injection below 10 parting pressure this lack of injector/producer 11 communication was over exaggerated. 12 Any questions on this slide? 13 (No comments) 14 MR. ADDAS: Okay. This is slide 15 and in this 15 slide we will discuss how next Meltwater production 16 turned negative. We define net production as gross 17 Meltwater production minus any production backed out by 18 Meltwater as spread in CPF2. To understand back out 19 costs by Meltwater we first need to discuss briefly how 20 fluids are being circulated in Meltwater. This has 21 been explained in the figure in bottom right. All 22 numbers shown in that cartoon are ballpark value. 23 Approximately 17,000 barrels per day of water was 24 coming down the water injection line into Meltwater out 25 of which 13,500 barrels per day of water was being AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 26 1 recycled back into the production line with the purpose 2 of preventing the production line from freezing. About 3 3,500 barrels per day of water went into the drillsite 4 out of which a thousand was injected into the reservoir 5 and about 2,500 was being used to lift the jet pump 6 valves. Coming back from the drillsite we had about 7 16,000 barrels per day of water which included the 8 2,500 from the drillsite lift water and the 13,500 9 recycled water. That 16,000 barrels per day of water 10 was accompanied by approximately 200 barrels per day of 11 oil production. The net water cut of that oil coming 12 back from Meltwater was about 98.7 percent. This 13 factor played a key role in backing out production 14 elsewhere in CPF2. 15 Total back out from Meltwater could be assigned 16 to three factors. First is the hydraulic back out 17 factor that is called to do all the fluids from 18 Meltwater flowing back in that 24 inch produced oil 19 line, the same produced oil line that is used for 20 production from 2L, 2N, 2S and 2M drillsites. The 21 schematics showing the production network can be seen 22 in the top right figure. Those fluids flowing back 23 from Meltwater in the produced oil line raises line 24 pressure that incrementally reduces production from all 25 the drillsites that feed into that same produced oil AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 27 1 line. Second factor is that CPF2 was handling 2 production from Meltwater with a water cut of greater 3 than 98 percent. We have facility gas and water 4 handling constraints in CPF2 and at times wells 5 elsewhere in CPF2 would get shut-in because CPF2 with 6 water or gas handling constraint. Fluid from Meltwater 7 could not be reduced primarily due to concerns of the 8 produced oil line freezing. The third factor was back 9 out caused due pump horsepower being devoted to 10 Meltwater water injection. That horsepower could have 11 been used elsewhere in injecting water and in turn 12 supporting more production. For example after 13 Meltwater was shut-in 18 injectors were brought online 14 elsewhere in CPF2. 15 The amount backed out by Meltwater is 16 calculated and not measured directly. As a result 17 there is some uncertainty in back out values and that 18 range varied from a high value of 560 barrels of oil 19 per day to a low value of 180 barrels of oil per day. 20 The mid case was about 350 barrels of oil per day. 21 This made Meltwater (indiscernible) oil production 22 negative implying that in keeping Meltwater alive we 23 were losing more oil elsewhere. Regardless of oil 24 price keeping Meltwater alive was not economic. All 25 these factors led to the decision to abandon Meltwater. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 28 1 Are there any questions? 2 CHAIR HUBER: Just a quick question is you're 3 talking about losing oil production elsewhere, you're 4 talking about the production rate daily, not the oil 5 itself because what's in the ground is in the ground? 6 MR. ADDAS: Correct. 7 COMMISSIONER CHMIELOWSKI: Was there any back 8 out due to the gas production at anytime..... 9 MR. ADDAS: Yes, when..... 10 COMMISSIONER CHMIELOWSKI: .....you know? 11 MR. ADDAS: .....when we were in continuous gas 12 injection we were producing a lot of gas especially 13 when we switched to lean gas injection sometime in 14 2015, we were getting a rapid turnaround of that gas 15 and that gas as the GOR continued to climb yes, it was 16 leading to more and more back out. That played a 17 central role in converting the drillsite to water. 18 COMMISSIONER CHMIELOWSKI: To water. Okay. 19 Thank you. 20 MR. ADDAS: Okay. We are on slide 16 where I 21 will summarize AOGCC engagements with ConocoPhillips 22 and starting status of the 2P drillsite. First 23 discussion with AOGCC and ConocoPhillips Alaska 24 occurred in February, 2021 where the potential to 25 indefinitely shut-in Meltwater was brought up. Later AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 29 1 that year a formal communication to indefinitely 2 shutting Meltwater was made to DNR and AOGCC by the 3 2021 Meltwater plan operating document. This was also 4 reiterated in the 2022 document. In November, 2021 5 AOGCC was briefed about abandonment plan and a further 6 update was provided in July of 2022. In regard to 7 Meltwater surface infrastructure and status all 8 pipelines have been blinded off and all fluids have 9 been evacuated from these pipelines. All surface 10 infrastructure has been isolated from production lines. 11 Some of this infrastructure has already been removed or 12 is being planned to be removed for use elsewhere. For 13 example the pig launcher is being moved to 2N from 2P 14 therefore there is no possibility of any future 15 production from Meltwater. All safety equipment still 16 remains connected and operational. That will remain 17 unchanged until all the wells in Meltwater are P&A'd. 18 This brings me to the conclusion of my 19 presentation. Before I hand it over to Ty Senden any 20 questions for me? 21 COMMISSIONER CHMIELOWSKI: Do you want to go 22 first? 23 CHAIR HUBER: Go ahead, Jessie. 24 COMMISSIONER CHMIELOWSKI: So you talked about 25 communicating with DNR about shutting -- indefinitely AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 30 1 shutting in Meltwater. Has there been any 2 communication with them about this full field shutdown 3 of Meltwater..... 4 MR. ADDAS: I mean, we..... 5 COMMISSIONER CHMIELOWSKI: .....DNR? 6 MR. ADDAS: .....yeah, we -- in the plan 7 operating document for 2021 that's what we communicated 8 that we are planning to..... 9 COMMISSIONER CHMIELOWSKI: Was that approved? 10 MR. ADDAS: Yeah. 11 COMMISSIONER CHMIELOWSKI: You don't know. 12 Okay. 13 MR. ADDAS: Yes, it was. 14 COMMISSIONER CHMIELOWSKI: Okay. I've just got 15 a couple questions related to -- I don't know if you 16 wanted to do those about -- well, I had a question on 17 your first slide when you talked about the possibility 18 of, you know, development drilling and that was never 19 pursued. Why was that? 20 MR. ADDAS: The Meltwater development drilling 21 process did not compete with other projects that we had 22 in ConocoPhillips Alaska portfolio. 23 COMMISSIONER CHMIELOWSKI: And was there any 24 consideration of converting wells to injection since 25 there was a need for more injection sounds like? AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 31 1 MR. ADDAS: No. I mean, we -- basically for us 2 to get that injection support you have to redrill wells 3 and make sure that wells are being completed in the 4 same load so that we can ensure that injection and 5 production support you have to redrill wells. And 6 without that it would be impossible to get that 7 injection support. 8 COMMISSIONER CHMIELOWSKI: Okay. 9 CHAIR HUBER: Ask a question on -- thank you 10 for slide nine and going through a little bit of the 11 history of this for me, I appreciate it. So initially 12 you went from what you thought was 120..... 13 MR. ADDAS: Hundred and twenty-five. 14 CHAIR HUBER: .....125 find and then you 15 revised that in 2012 down to 60..... 16 MR. ADDAS: Right. 17 CHAIR HUBER: .....right, and then you've 18 provided estimates of what you've collected to date. 19 It looks like you're still about what, 10 percent low 20 at the original estimates were for recovery..... 21 MR. ADDAS: No, in the 20..... 22 CHAIR HUBER: .....from the 60? 23 MR. ADDAS: .....in the 2012 hearing we said 24 total recovery would be between 30 to 35 percent and I 25 believe we are today at 33.6 percent. So we are AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 32 1 exactly in between the range that was communicated in 2 2012. 3 CHAIR HUBER: Okay. Was there a time that 4 there was a discussion about potentially using -- 5 figuring out a way to get into those reservoir lobes 6 and incrementally pulling some more oil from that? I 7 have notes that there was an incremental three to 8 seven. 9 MR. ADDAS: Right. That was again with 10 development drilling. Yeah, I mean, with development 11 drilling there was a potential of recovering two to 7 12 million barrels additional oil, but again Meltwater 13 economics of those projects did not compete with other 14 projects that we had in our portfolio so they were not 15 pursued. 16 CHAIR HUBER: How about potential utilization 17 of this pad and field in the future, are there anything 18 else that you might reach with this is what -- what's 19 contemplated? 20 MR. ADDAS: I will defer. 21 CHAIR HUBER: What are we potentially 22 foreclosing I guess is what I'm asking. 23 MR. PERFETTA: Yeah, I can take that. As part 24 of the field abandonment project we looked at 25 exploration potential in the immediate area and nothing AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 33 1 was identified. 2 COMMISSIONER CHMIELOWSKI: Nothing on this 3 section, no. 4 CHAIR HUBER: Thanks. 5 MR. SENDEN: All right. We'll move on to slide 6 17. 7 CHAIR HUBER: That brings you to the P&A piece? 8 MR. SENDEN: We'll move on to slide 17. In the 9 next few slides I will provide a brief high level 10 overview of our planned Meltwater well abandonment 11 program. As Sayeed mentioned at this time we are not 12 seeing any AOGCC approvals to the abandon the Meltwater 13 pad, rather seek AOGCC approval for individual well P&A 14 sundries and hopefully subsequent slides and discussion 15 provides a context to get those requests through. 16 Moving on to slide 18. At this time I will 17 provide a brief pressure containment review beginning 18 near the surface. For this discussion I've considered 19 the overburden the zone between surface down to surface 20 casing shoes. The shoes range in depth from 2,236 feet 21 to 3,713 feet measured depth which correlates to a true 22 vertical depth of 2,160 and 2,448 respectively. As Pat 23 mentioned previously the overburden zone has a frack 24 gradient estimated at .84 psi per foot or just over 25 1,900 psi at an average TVD of 2,300 feet. This AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 34 1 equates to a 16.2 pound per gallon equivalent mud 2 weight. 3 Moving down the slide, I apologize, it's cut 4 off there a bit. 5 COMMISSIONER CHMIELOWSKI: So excuse me, the 6 confining zone equivalent mud weight was determined by 7 FITs or LOTs? 8 MR. SENDEN: Correct. 9 COMMISSIONER CHMIELOWSKI: Okay. 10 MR. SENDEN: Surface casing isolation, i.e., 11 the shoes, were set below the permafrost depths. All 12 surface casings have full cement returned and had 13 initial formation integrity slash leakoff test between 14 14.6 and 18.1 pounds per gallon equivalent. And it 15 should be noted that most of these wells have -- 16 currently have open shoes and therefore we believe that 17 the OA surface pressures that we read are a direct 18 measurement of the C80. 19 Production casing. Sixteen of the 19 wells had 20 full returns when cementing. Over the years we've had 21 some waterflow logs run on the injectors and we have 22 never seen water injecting upwards from the 23 perforations. This would suggest again that the OA 24 pressures are not a direct conduit from the 25 perforations rather than the pressure and/or fluid is AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 35 1 transferring through the reservoir to adjacent oil. 2 COMMISSIONER CHMIELOWSKI: Could you just go 3 over again and describe the path that the MI took when 4 it went out of the approved injection rule, you're 5 saying it went into the approved injection interval and 6 outside of the wellbore came to another zone..... 7 MR. SENDEN: Right. 8 COMMISSIONER CHMIELOWSKI: .....through the 9 fractures? 10 MR. SENDEN: Yeah. So we..... 11 COMMISSIONER CHMIELOWSKI: Right. 12 MR. SENDEN: .....we did not ever measure any 13 injection fluids traveling vertically up the -- up the 14 wellbore itself. And therefore to get from the 15 perforations of an injection well to any other outer 16 annulus where we measure pressure it had to have gone 17 through the reservoir, through one of the lineaments or 18 other fractures on this. 19 COMMISSIONER CHMIELOWSKI: Thank you. 20 MR. SENDEN: Okay. Moving on to slide 19. One 21 of the reasons that we're here today is that the AOGCC 22 has questioned whether our downsqueeze method complies 23 with 20 AAC 25.112. That regulation requires a 24 reservoir cement plug (indiscernible) fluid between 25 that and the 150 foot required surface cement plug. We AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 36 1 certainly have both the reservoir and surface cement 2 plugs covered in our design and our convinced that our 3 abandonment design meets all the regulatory 4 requirements. The OA shoes are scattered around the 5 depths of the C80 sands and as I mentioned earlier we 6 believe the measured OA pressures are direct 7 representation of the C80 sand. The current OA 8 pressure and equivalent mud weight of 8.8 pound per 9 gallon however have been as 11.0 pound per gallon in 10 the 2010 height of injection. 11 The downsqueeze, our proposed plan, results in 12 a minimum of 2,000 foot annulus of solid cement. The 13 downsqueeze doesn't require us to compromise the 14 integrity of perfectly healthy casing which also acts 15 as a barrier. And lastly, we feel the downsqueeze is 16 the best option for knowing how much cement we're 17 putting and where that cement is going. With 18 geological barriers preventing upward migration and an 19 annulus full of cement we are confident that the 20 permanent isolation will be achieved. 21 Any questions on plugging it? 22 COMMISSIONER CHMIELOWSKI: Yes, I have some 23 questions. As you know AOGCC regulations require that 24 hydrocarbons be confined to their strata. And it 25 sounds as though -- it reads here that there's just the AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 37 1 belief of where the gas is, not necessarily any data. 2 So is ConocoPhillips' P&A strategy just based on a 3 belief, what evidence is there to show that these 4 hydrocarbon zones are accurately identified and 5 isolated? 6 MR. SENDEN: I mean, we believe as Pat said 7 that the C80 reservoir which is at or near the shoes of 8 our service casing is continuous enough and we have 9 measured pressures higher and lower, we can leave, we 10 can pump into, and we just -- we believe that that is 11 where our excess gas has been injected. We have 12 fingerprints that would indicate that. 13 COMMISSIONER CHMIELOWSKI: What fingerprints 14 are those? 15 MR. SENDEN: Gas samples that have been 16 collected. 17 COMMISSIONER CHMIELOWSKI: That indicate it's 18 MI? 19 MR. SENDEN: Indicated it's MI or just 20 injection gas. 21 MR. ADDAS: Yeah. So we have recently 22 collected gas samples from three wells where two of 23 them were actually (indiscernible) reflected biogenic 24 gas so not -- not MI. And one of them, 2P431, still 25 resembles MI. It has always been one of those problems AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 38 1 of -- from the beginning, it still resembles MI. 2 CHAIR HUBER: Sir, are you referring to 3 isotopic fingerprints? 4 MR. ADDAS: Yes, exactly. 5 CHAIR HUBER: Thank you. 6 COMMISSIONER CHMIELOWSKI: So could you -- do 7 you have a, you know, schematic that shows -- it looks 8 like on this one you estimate top of cement at about 9 5,782 and then the base of the surface casing is 3,713 10 so that's about 2,000 feet of uncemented reservoir or 11 formation..... 12 MR. SENDEN: Right. 13 COMMISSIONER CHMIELOWSKI: .....right? And 14 when you do -- when you propose this downsqueeze how 15 far down would the cement go below the surface casing 16 shoe and how would you know where it ends? 17 MR. SENDEN: We don't know. We know it will 18 come out the bottom obviously it's an open shoe. We 19 don't know at that point laterally how far out it will 20 transmit or whether it just goes vertically down. 21 There -- there's no intent to try to pump an OA squeeze 22 or an OA cement job that will then connect the cemented 23 production case. 24 COMMISSIONER CHMIELOWSKI: Is it possible to 25 log it and, you know, confirm integ -- you know, AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 39 1 quality of cement along the squeeze? 2 MR. SENDEN: It's not possible to log it while 3 the tubing is in place. 4 COMMISSIONER CHMIELOWSKI: Okay. Is it 5 possible that by doing the OA downsqueeze you could 6 potentially frack the confining layer and create a 7 conduit to surface that way? 8 MR. SENDEN: It is possible. We don't believe 9 that will be the case. We can actively pump into the 10 majority of these wells. We do have one well that has 11 a cemented annulus already, we have a second well that 12 I'm familiar with that has a cemented shoe so we cannot 13 pump into those. Other methods will be -- will be 14 chosen and just identified on the end of this rule 15 finder. Did I answer your question? 16 COMMISSIONER CHMIELOWSKI: Yeah, I'm just -- 17 I'm just trying to get information on the record is 18 really the point of these questions. So to summarize 19 ConocoPhillips proposes to pump an OA downsqueeze that 20 would go just below surface casing shoe, but there's no 21 way to verify the qualify of the cement or pressure tag 22 it -- pressure test it or tag it? 23 MR. SENDEN: We will pressure test, but there's 24 no way..... 25 COMMISSIONER CHMIELOWSKI: At surface. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 40 1 MR. SENDEN: to tag it. 2 COMMISSIONER CHMIELOWSKI: Right. Yeah. Okay. 3 What other alternatives has ConocoPhillips considered 4 for these wells besides OA downsqueeze? 5 MR. SENDEN: There are -- there are other 6 alternatives and those would require perforating or 7 milling the existing production casing and we believe 8 that that compromises the casing enough that it does 9 actually reduce one of your potential barriers. 10 COMMISSIONER CHMIELOWSKI: I understand there 11 has been on 3S drillsite a perf and wash campaign 12 to..... 13 MR. SENDEN: Correct. 14 COMMISSIONER CHMIELOWSKI: .....place them into 15 cross shallower zones and how does that play into plans 16 for future P&As? 17 MR. SENDEN: So that selection -- that method 18 was selected for 3S drillsite because we are actively 19 developing a shallow reservoir that is in that strata. 20 Because there will be no further development on 2P pad 21 we believe the best method is to - the downsqueeze. 22 COMMISSIONER CHMIELOWSKI: Has the perf and 23 wash method been successful as far as you know? 24 MR. SENDEN: I am not directly involved in 25 that. I believe we've had some successes, I believe AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 41 1 we've had some challenges..... 2 COMMISSIONER CHMIELOWSKI: Uh-huh. 3 MR. SENDEN: .....but I'm not directly involved 4 in that. 5 COMMISSIONER CHMIELOWSKI: Okay. So I had a 6 list of questions if you don't mind if I go through 7 those. 8 CHAIR HUBER: Okay. 9 COMMISSIONER CHMIELOWSKI: Okay. So and maybe 10 these are more detailed, but on well 2P422 I understand 11 that there was an OA pressure that was climbing. What 12 is the status of that well? 13 MR. ADDAS: Yes, that is one of the wells where 14 we collected the gas sample and we analyzed it and it 15 does not resemble MI, it resembles more of biogenic 16 gas. 17 COMMISSIONER CHMIELOWSKI: Okay. So native 18 gas? 19 MR. ADDAS: Native gas, yes. 20 COMMISSIONER CHMIELOWSKI: And what is the 21 status of that, is it still climbing? 22 MR. ADDAS: Yeah, a very, very slow climb..... 23 COMMISSIONER CHMIELOWSKI: Okay. 24 MR. ADDAS: .....in the pressure, yeah. 25 COMMISSIONER CHMIELOWSKI: Does management AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 42 1 bleeds? 2 MR. ADDAS: If necessary, if the pressure..... 3 COMMISSIONER CHMIELOWSKI: Okay. 4 MR. ADDAS: .....goes above the (indiscernible) 5 limit, yeah, we'll bleed it..... 6 COMMISSIONER CHMIELOWSKI: Okay. 7 MR. ADDAS: .....bleed it down again, yeah. 8 COMMISSIONER CHMIELOWSKI: And there was I guess 9 an OA bleed and load project about a year ago; is that 10 correct? 11 MR. SENDEN: That's correct. 12 COMMISSIONER CHMIELOWSKI: And how does that bleed 13 and load project indicate pressure communication with 14 the C37, is that..... 15 MR. SENDEN: I believe C80 or C..... 16 COMMISSIONER CHMIELOWSKI: Is it C80? 17 MR. SENDEN: Yeah. 18 COMMISSIONER CHMIELOWSKI: Okay. 19 MR. ADDAS: So when we -- when we charge the 20 OAs during the bleed and load project so basically the 21 purpose was to see whether or not we are seeing gas 22 migrating to the OA of post (indiscernible), right. 23 And so that's what we saw in three of those wells, gas 24 did migrating and we saw the pressure rise. The 25 purpose was to see which wells were still problematic AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 43 1 with respect to gas communicating in the OA all the way 2 to the surface via the..... 3 COMMISSIONER CHMIELOWSKI: Okay. 4 MR. ADDAS: .....annulus. So then the next 5 step was to do the isotoping analysis after getting the 6 gas samples. And then we analyzed them on two wells, 7 422 and 424. 424, the last time we talked with AOGCC 8 we had not reported that well. That well showed up 9 later on so we're reporting it today. Both of those 10 wells, the fingerprint was -- basically resembled again 11 biogenic gas. 431, the other well, has always been the 12 problem well from the beginning, still resembles MI. 13 COMMISSIONER CHMIELOWSKI: Okay. 14 MR. ADDAS: And 2P431 is one of those wells 15 located in the central conduit that Pat Perfetta was 16 talking about that probably could have extended more 17 higher up. So but all other wells are doing fine, we 18 have not seen any change in the fluid levels that are 19 (indiscernible)..... 20 COMMISSIONER CHMIELOWSKI: Thank you. So for 21 one of the wells, 2P447, ConocoPhillips plans a 22 workover for that well. It, you know, involves what, 23 decompleting the well, logging to determine that bond, 24 cementing, doing a draw down test, I don't -- perhaps 25 observing for a period of time to understand if that AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 44 1 plug is holding. Why not apply that method to all 2 wells on Meltwater? 3 MR. SENDEN: I think the plan to use a rig 4 would be for those particular wells that we can't pump 5 into the OA. We -- again we don't necessarily believe 6 that pulling tubing and cementing and logging is -- 7 provides any better quality of abandonment and rather 8 is a misuse of our resources where we could be putting 9 them to work somewhere else. 10 COMMISSIONER CHMIELOWSKI: Has Conoco 11 considered a phased approach to plugging these wells as 12 far as understanding the effectiveness of the plugs 13 over time. I understand that if you, you know, pump an 14 OA downsqueeze and it's a failure what -- there are no 15 remediation options. So what are your thoughts on 16 that? 17 MR. SENDEN: Yeah. So that was kind of getting 18 into my next slide. 19 COMMISSIONER CHMIELOWSKI: Okay. 20 MR. SENDEN: But -- but, yeah. So we do plan a 21 phased approach and we do plan -- it's sort of 22 interchangeable between -- I don't know if you want me 23 to just move to that? 24 COMMISSIONER CHMIELOWSKI: Sure. That would be 25 great. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 45 1 MR. SENDEN: Okay. Yeah, let me just -- so 2 this is just a generic example and again we've used 3 this -- this downsqueeze technique on nearly all of our 4 abandonments to date with the exception of the 3S wells 5 and the abandonment steps are as follows. One, perform 6 an injectivity, do your downsqueeze of your outer 7 annulus and we would do that across the entire pad, all 8 19 wells, and then we could monitor if -- the other 9 option would be do your reservoir plug first, monitor 10 that and then do your downsqueeze. It would be on a 11 resource base for us, but the plan would be to monitor 12 the outer annulus for sometime. If at that point, you 13 know, we have positive pressure and no pressure at 14 surface then we would continue with the program. There 15 would be at the time if we did not get a positive 16 pressure or we did see pressure at surface we would 17 have to put a rig on that particular well. 18 COMMISSIONER CHMIELOWSKI: So you're talking 19 about monitoring the OA after the OA downsqueeze? 20 MR. SENDEN: Correct. 21 COMMISSIONER CHMIELOWSKI: How would you 22 monitor an OA full of cement? 23 MR. SENDEN: Well, we'll just make sure there's 24 no pressure at surface via surface gauges. 25 COMMISSIONER CHMIELOWSKI: No more questions at AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 46 1 this time. 2 CHAIR HUBER: Okay. So I heard you use the 3 word solid cement. 4 COMMISSIONER CHMIELOWSKI: Put your..... 5 CHAIR HUBER: I'm sorry. Sorry. Pat, I heard 6 you use the word solid cement, 2,000 feet of solid 7 cement. But what we're talking about hopefully is 8 continuous cement, right, we don't have a way to gauge 9 how well that cement is filling that area or tap that 10 cement or do those things that we would normally do; is 11 that correct? 12 MR. SENDEN: Correct. 13 CHAIR HUBER: And we also talked a little bit 14 about that we believe that this is communicating in 15 that gas layer and we believe it was from the fracture 16 that potentially extends above the surface noise, 17 right, from the seismic, but we have no way of testing 18 that either. Has there been or would there be any 19 ethicacy to testing if you believe that's residual 20 native gas pressure to putting another hole in and 21 testing that separate from these wells that you're 22 dealing with? 23 MR. SENDEN: We had not considered that. 24 CHAIR HUBER: I mean, it seems to me that if 25 you -- if you have that pressure continuous, that AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 47 1 native gas pressure, that's going to be a piece of 2 information that we don't necessarily have at this 3 point? 4 MR. SENDEN: Yeah, we -- so we -- in the late 5 2000s, prior to 2000 and as late as prior to 2012 we 6 had -- when we were over injecting we had reservoir 7 pressures that were substantially higher than we're 8 seeing now. And we're upwards of probably half of what 9 we saw during those injection periods. We have since 10 then, you know, reduced our injection to below parting 11 pressure at the sandface and we believe that should 12 there be any sort of breach or injection into the 13 overburden we would have seen it at that time. And so 14 we firmly believe that the gas is -- while it may be 15 mobile from the reservoir to C37 and to C80 that it is 16 -- will not -- we don't expect to see it above the C80. 17 So while we can't stop the gas from moving from C37 to 18 C80 or from Bermuda to C37, we feel that our techniques 19 and our methods certainly will prevent it from coming 20 to surface. 21 CHAIR HUBER: Thank you. 22 MR. SENDEN: I fear that if we poke more holes 23 in it we have more -- we have more wells then we have 24 to deal with and more wells to abandon. 25 CHAIR HUBER: Thank you. I appreciate that. AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 48 1 Do you have additional questions, Jessie? 2 COMMISSIONER CHMIELOWSKI: Not at this time. 3 Possibly we could take a recess. 4 CHAIR HUBER: Okay. So perhaps..... 5 COMMISSIONER CHMIELOWSKI: Yeah. 6 CHAIR HUBER: .....we'll take a short recess at 7 this point so we can coordinate with Staff and then 8 come back on the record following. 9 COMMISSIONER CHMIELOWSKI: Maybe 20 minutes. 10 Should we say 11:20? 11 CHAIR HUBER: Let's shoot for 11:20. 12 COMMISSIONER CHMIELOWSKI: Okay. Great. 13 CHAIR HUBER: Thank you. 14 COMMISSIONER CHMIELOWSKI: Thank you. 15 (Off record) 16 (On record) 17 CHAIR HUBER: Thank you. We'll come back on 18 the record now with my microphone on this time. We did 19 have just a couple of questions that we'd like to 20 continue to explore with you gentlemen and, Jessie, you 21 have some questions you'd like to begin with. 22 COMMISSIONER CHMIELOWSKI: Yes. Thank you. 23 You know, I wanted to talk about those three fractures 24 that have been identified. And, you know, there are I 25 guess three wells that have OA pressure currently; is AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 49 1 that correct? 2 (No audible response) 3 COMMISSIONER CHMIELOWSKI: Should -- are those 4 -- how do those wells relate to the fractures and 5 should wells near the fractures be handled differently? 6 MR. PERFETTA: So I guess I would say that..... 7 COMMISSIONER CHMIELOWSKI: Could you state your 8 name for the record just so we know. 9 MR. PERFETTA: Oh, yes. This is Pat Perfetta. 10 COMMISSIONER CHMIELOWSKI: Thank you. 11 MR. PERFETTA: And so I'd say that the 12 interpretation based on the best of our knowledge is 13 that those fractures are currently closed since we 14 stopped our injection above parting pressure. So they 15 should no longer be transmitting any pressure or gas 16 from the reservoir to the overburden. 17 COMMISSIONER CHMIELOWSKI: So how do the wells 18 with OA pressure, how do they relate I guess spatially 19 to those fractures, they still have OA pressure, 20 correct? 21 MR. PERFETTA: Uh-huh. 22 COMMISSIONER CHMIELOWSKI: Yeah. 23 MR. PERFETTA: Yeah, and that was likely from 24 the time whenever those fractures were being propagated 25 open due to over injection so they are currently AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 50 1 closed. We'd have to go back on an individual well 2 basis and look exactly where those intersections occur. 3 COMMISSIONER CHMIELOWSKI: So those three wells 4 are not necessarily..... 5 MR. PERFETTA: They're not..... 6 COMMISSIONER CHMIELOWSKI: .....really close 7 proximity say to the central fracture, they're..... 8 MR. PERFETTA: Correct. They're not 9 necessarily..... 10 COMMISSIONER CHMIELOWSKI: Okay. Got it. 11 Okay. Thank you. 12 MR. PERFETTA: Uh-huh. 13 COMMISSIONER CHMIELOWSKI: And can we go to 14 slide 19, please. So let me get some of my paper here. 15 You know, as we stated in the notice for this hearing 16 one of the purposes of holding it is that the proposed 17 execution plan for these P&As requires waivers from our 18 plugging requirements under 25.112. But on slide 19, 19 you know, you address the AOGCC concern about whether 20 the downsqueeze complies with our regulation, but you 21 don't really say or I haven't heard you say how it 22 meets the regulation. And I guess I would talk 23 specifically about regulations that requiring the 24 adequacy of cement, the location of the cement, 25 preventing migration between strata, making sure the AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 51 1 hydrocarbons are constrained in the formation and that 2 the operator shall record the location and integrity of 3 cement plugs that are required. So could you please 4 speak to how this plan meets AOGCC regulations? 5 MR. SENDEN: So -- excuse me, this is Ty 6 Senden. Part of the regulation also requires a 7 reservoir plug and a surface plug. And I don't think 8 any method of abandonment will keep potential 9 hydrocarbons from moving from Bermuda to C37 to C80. I 10 think that has happened, it will happen and our 11 attempts to abandon these wells will be to keep it from 12 coming to surface. Now we have -- cannot tag this OA 13 plug, we can our reservoir plug and we can pressure 14 test both plugs. Historically that has been the 15 approved method. 16 COMMISSIONER CHMIELOWSKI: Does Conoco have any 17 statement then on whether it's requesting a waiver or a 18 variance from regulations? 19 MR. SENDEN: We will request a waiver or a 20 variance if the -- to comply with the regulations if 21 that's 22 COMMISSIONER CHMIELOWSKI: Okay. So AOGCC's 23 position in setting the hearing was that it required a 24 waiver. So if that's what you're saying also is that 25 this proposed plan requires a waiver from our AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 52 1 regulations? 2 MR. SENDEN: Our sundry application will 3 request that. 4 COMMISSIONER CHMIELOWSKI: Right. Okay. Is 5 there anything that I missed, Commissioner Huber? 6 CHAIR HUBER: Not that I can think of. We 7 talked a little bit about potential for waste or oil 8 that's going to be left down there in some of those 9 pieces of formations, that's what four -- two to seven, 10 four to 7 million barrels? 11 MR. ADDAS: Yes. This is Sayeed again. Yes, 12 two to 7 million barrels if development drilling was 13 pursued. 14 CHAIR HUBER: If development -- and it's a 15 factor of it's got to be economically feasible for you 16 to go after that oil, you're making those 17 determinations based on your company's business plan, 18 correct? 19 MR. ADDAS: Correct. It has to compete with 20 other projects that we have in our portfolio and 21 unfortunately it didn't, those projects did not 22 compete. 23 CHAIR HUBER: So the pressure back down or the 24 back out that you're doing now, will that have an 25 impact on other fields or what they're producing, not AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 53 1 just Meltwater itself? 2 MR. ADDAS: Yes. All satellites like, you 3 know, they all have a back out, but typically the back 4 out is much less than the gross production. So the net 5 production from the field is positive, they're always 6 looking at that. For Meltwater it turned negative 7 which is why we are abandoning it. 8 CHAIR HUBER: Okay. Thank you. 9 MR. ADDAS: Yeah. 10 COMMISSIONER CHMIELOWSKI: I think that's all 11 we had. 12 MR. PERFETTA: Thank you, Commissioner. 13 CHAIR HUBER: Thank you, appreciate the 14 presentation. We're coming to the point now where 15 we're going to ask if there's anybody from the public 16 that wishes to testify on this. This is -- this 17 Commission serves the public in corralling, 18 maintaining, preserving, conserving our hydrocarbon 19 resources as well as our safety, as well as the 20 groundwater. So it's important that the public has an 21 opportunity to testify. If we have anybody from the 22 public that's signed up we'd love to hear from you now 23 or do we have anybody on Teams, Sam? 24 (No comments) 25 CHAIR HUBER: Anybody in the room? AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 54 1 (No comments) 2 CHAIR HUBER: Seeing and hearing nobody 3 interested in public testimony I believe that we've 4 concluded our business today and we can adjourn this 5 hearing at 11:37 a.m. 6 (Hearing adjourned - 11:37 a.m.) 7 (END OF PROCEEDINGS) 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 AOGCC 1/19/2023 ITMO: ABANDOMENT OF KUPARUK RIVER UNIT DRILLSITE 2P DOCKET NO OTH 22-027 329 F Street, Ste. 222., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Computer Matrix, LLC Phone: 907-227-5312 Page 55 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 55 are a true, 4 accurate, and complete transcript of proceedings in 5 Docket No.: OTH-22-027, transcribed under my direction 6 from a copy of an electronic sound recording to the 7 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 Kuparuk River Unit Meltwater Field (Drillsite 2P) Plugging and Abandonment 1 Acronyms Reference List •AAC:Alaska Administrative Code •AIO:Area Injection Order •CPF: Central Processing Facility •EMW:Equivalent Mudweight •FIT:Formation Integrity Test •GI:Gas Injection •GOR:Gas Oil Ratio •IA:Inner Anulus •KRU:Kuparuk River Unit •LOT:Leak Off Test •MMBO:Million Barrels Oil •MW:Meltwater •OA:Outer Anulus •OOIP:Original Oil in Place •PA:Participating Area •P&A:Plug and Abandon •PO:Produced Oil •PPG:Pounds Per Gallon •T x IA:Tubing by Inner Anulus •WI:Water Injection 2 Objective/Agenda •Objective o CPAI is seeking sundry approvals to P&A 19 Meltwater wells in 2023-2024 winter season o CPAI is not seeking waivers or variances from AOGCC regulations, as we believe our P&A plans comply with all terms of 20 AAC 25.112 •Agenda o Field Overview & Geologic Background o Production/Injection History o Field Abandonment Context o Plugging & Abandonment Design 3 Field Overview & Geologic Background 4 Meltwater Field Location, and Well Information •Southernmost satellite of Kuparuk River Unit •Drillsite 2P •Approximately 10 miles south of drillsite 2N •Meltwater wells: •Discovery well: MWN 2 •Delineation well: MWN 1 •Producers: 11 •Injectors: 8 •Abandoned bore holes: 4 •All wells currently shut-in Meltwater PA Kuparuk River Unit Meltwater Field Spider Map 1 Mile Drillsite 2P 2N 2P 5 Miles 5 +Producer P&A’d Injector Meltwater Area Geologic Overview •Meltwater Oil Pool: Bermuda Reservoir ―Seabee Formation ―Depositional setting: Slope canyon fill Turbiditic channels, and lobate features Compartmentilization present ―Many sand bodies laterally discontinuous between wells Type Log: Meltwater N2 C-37 Marker C-80 Marker Meltwater Oil Pool Bermuda Reservoir Base Permafrost Surface Casing Top West Sak Seabee Distal Tuluvak Equivalent Lower Schrader Bluff Middle Schrader Bluff Upper Schrader Bluff Prince Creek Formation Upper mappable extent of linear 4-D time-shifts ~200’ below C-37 Meltwater Field Well Spider Map A A’ A A’ Base West Sak Geo-seismic Section Markers/Descriptors 6 Gross Bermuda Shallow Stratigraphic Cross-Section (Datum: C-80 Marker) 7 •Surface casing typically set between base West Sak, and C-80 Marker •Interval above, and below C-80 contains sandy intervals -> Lithology descriptions & petrophysical interpretation •Laterally continuous marine shales present below base permafrost within lower portion of West Sak progradational cycles ―Fracture gradient of correlative shales is in the area of West Sak development is up to ~0.84 psi/ft ―Likely barriers to vertical fluid movement Top West Sak Base Permafrost Base West Sak C-80 Marker B’ B B’ C-80 intersection point Surface casing set depth B Log Legend C-80 Sands Reservoir Engineering Background 8 AOGCC Hearings & Meltwater Recovery factor Estimations •AIO And Pool Rules hearing (May 2001): ―OOIP of 125 MMBO estimated with estimated recovery of 52 MMBO (~ 41.6% recovery factor) ―Prior to drillsite came online ―Estimate included upside potential in peripheral development •AIO 21 amendment hearing (Nov 2012): ―OOIP of 60 MMSTB (updated after drilling results and 2008 seismic) ―Estimated total recovery factor between 30-35% (provided during Q&A; transcript page 90) ―Recovery factor estimated from field performance •AIO 21(a) amendment hearing (July 2015) ―Incremental recovery of 2-7 MMBO if development drilling was pursued ―No development wells drilled in 2P since then •Total oil recovered 20.28 MMSTB. Recovery factor of 33.8% when field was shut in •Key factors influencing recovery factor include ―Injection below parting pressure ―Geological complexity, compartmentalization and lack of communication between injector and producer 9 Production history Oil Rate (STB/D)Water Rate (STB/D)Form. Gas Rate (MSCF/D)WI Pipeline corroded Sand Face Inj Pressure Limit GI pipeline to WI Water production from 2P-432, injector converted to producer 10 Injection history WI Pipeline corroded GI pipeline to WI Sand Face Inj Pressure LimitWater InjRate (STB/D)Gas InjRate (MSCF/D)11 GOR Response GOR (SCF/STB)Gas InjRate (MSCF/D)Continuous gas injection from 2009-19 led to GOR increase over time High GOR made wells uncompetitive 2018: Decision taken to convert field to water injection 12 Recent Production 13Water, Prod STB/DGOR, SCF/STBOil, STB/DConversion to WINo gas lift in drillsite Two producers converted to jet pump PO line froze Recent Injection 14Water, STB/DGas Injection Rate MSCF/DLoss in injectivity WI limited to sandface pressure limit Backout Total backout Hydraulic Facility constraints Water injection •Minimum 15,000 BWPD in injection line to minimize corrosion •Water in PO line helps in prevent freezing of Cross-country line during winter •Backout estimated from 560 BOPD to 180 BOPD with a mid case of ~ 350 BOPD •Net Meltwater production is negative •By reducing the recycle water, we brought 8 injectors back online elsewhere in CPF2 15 13,500 BWPD Recycle 17,000 BWPD 3,500 BWPD 2,500 BWPD from jet pumps16,000 BWPD Meltwater Abandonment Status AOGCC Engagement to Date: •Feb 2021: First engagement with AOGCC on potential to indefinitely shut-in Meltwater •June 2021: Communicated to AOGCC and DNR decision to indefinitely shut-in Meltwater •Nov. 2021: Briefed and consulted with AOGCC on well abandonment plan •July 2022: Briefed and consulted with AOGCC and provided an update on well abandonment plan Meltwater Surface Equipment Status: •All pipelines are blinded off and all fluids have been evacuated •Surface infrastructure is disconnected from production lines ―Equipment is being evaluated for reuse on other KRU locations, removal happening based on evaluation •All safety equipment remains connected and operational, and this will remain the case until the wells are P&A’d 16 Plugging and Abandonment Design 17 Pressure Containment Review Overburden: •Confining zone frac gradients are estimated at 0.84 psi/ft ―16.2 ppg EMW Surface Casing Isolation: •Set below permafrost depth •All wells, full cement in returns •Original FIT/LOT tests ranged from 14.6 –18.1 ppg EMW Production Casing/Reservoir Isolation: •Successful reservoir isolation during initial well construction ―16 of 19 had full returns •Historical waterflow logs at or near the perforations of the injection wells have measured no upward flow along the wellbore •Wellbores are not the direct conduit from the reservoir 18 B’B Design Overview 19 Concern: •AOGCC has questioned whether our downsqueeze complies with 20 AAC 25.112 CPAI Design Criteria: •We believe the OA pressures are a direct representation of the C80 sand ―Current OA pressures indicate 8.8 -9.0 EMW << 16.2 EMW of the overburden/confining zone •OA downsqueeze most adequately contains the shallow sands with >2000 ft of continuous cement to surface •Doesn’t compromise integrity of existing casing •Know where and how much cement was placed OA Downsqueeze Conductor: 16" Conductor 110' KB Production Casing Cement: 62.5 bbls of 15.8# Class G Cement Calculated TOC @ 5,782' KB 1 2 3 5 4 Production Casing : 5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#, L-80 BTC Mod Set @ 9,025.8’ KB T-3 Peforations: @ 8,640' – 8,650' KB (10') Surface Casing: 7-5/8", 29.7#, L-80 BTC Mod Set @ 3,713' KB Production Tubing: 3 ½”, 9.3# L-80 EUE-8rd Set @ 8,208.4' KB 6 C37 Formation Top: 6,214' KB C80 Marker Top: 3,760' KB Generic Design 1/19/2023 20 Example •Plug #1: OA Downsqueeze 1.Perform injectivity test 2.Bullhead arctic-grade, cold-temp cement slurry with adequate volume to cover the C80 marker 3.Monitor annulus to confirm no pressure build •Plug #2: Reservoir Squeeze 1.Set retainer and perform injectivity test 2.Via coil tubing, squeeze perfs with cement slurry. •Plug #3: Tubing x IA 1.Shift sliding sleeve, pull GLV or punch tubing 2.Perform injectivity test 3.Circulate tubing and IA surface to surface with 15.8 ppg arctic-grade, cold-temp cement slurry. OA Downsqueeze Reservoir Squeeze T x IA Plug Conductor: 16" Conductor 110' KB Production Casing Cement: 62.5 bbls of 15.8# Class G Cement Calculated TOC @ 5,782' KB 1 2 3 5 4 Production Casing: 5.5" x 3.5" @ 8,210' KB, 15.5# x 9.3#, L-80 BTC Mod Set @ 9,025.8’ KB T-3 Peforations: @ 8,640' – 8,650' KB (10') Surface Casing: 7-5/8", 29.7#, L-80 BTC Mod Set @ 3,713' KB Production Tubing: 3 ½”, 9.3# L-80 EUE-8rd Set @ 8,208.4' KB 6 C37 Formation Top: 6,214' KB C80 Marker Top: 3,760' KB 21 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. From:Senden, R. Tyler To:Carlisle, Samantha J (OGC) Cc:Senden, R. Tyler Subject:Meltwater Hearing 1/19/23 Date:Friday, January 20, 2023 8:20:05 AM Samantha, Could you please forward this to the Commissioners for us. Thank you! Dear Commissioners: Commissioner Chmielowski asked at the Meltwater hearing yesterday whether ConocoPhillips is seeking a variance from the requirements of 20 AAC 25.112. To clarify, we are not seeking a variance from 20 AAC 25.112, as we believe our proposed OA downsqueeze plan complies with all of the requirements of that regulation. Specifically, 20 AAC 25.112(c), which is the regulation pertaining to cased wells (the Meltwater wells are all cased wells), requires: “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.” As we stated in our testimony, migration of miscible injectant (MI) from the Bermuda formation to the C37 and C80 has already occurred, and all available data indicate that such migration occurred via lineaments (see slide 6 of our presentation), not via the well bores. As stated in our testimony and on slide 19 of our presentation, the OA downsqueeze, coupled with the laterally contiguous confining layers above the base of the surface casing (see slides 7 and 18), provide assurance that hydrocarbons in the C80 will remain confined to that zone without migration to surface. In addition, the OA downsqueeze will maintain the integrity of the existing production casing, providing an additional and important barrier to fluid migration through the wellbore. 20 AAC 25.112(c)(1) requires that perforated intervals be plugged via one of certain listed methods, including via cement retainer placed 50-500 feet above the perforated interval. Our proposed plan complies with this requirement. Per 20 AAC 25.112(g)(2), the downhole plug will be tagged and tested. Under 20 AAC 25.112(g), the surface plug does not need to be tagged or tested. However, per our plan, the surface plug also will be tested and can be considered “tagged” as it is physically visible at surface. 20 AAC 25.112(d) pertains to surface plugs, and our plan meets all of those requirements, specifically the criteria of subsection (d)(2)(A) (see also slides 19-20 of our presentation), as well as the requirements of subsection (e) (see slide 20 of our presentation). 20 AAC 25.112 does not require cement logs. However, as stated in our testimony, per our plan, cement quality will be assured by post-downsqueeze monitoring of the OAs for any positive pressure. In sum, our proposed downsqueeze method – the method employed for nearly all prior North Slope wells – fully complies with 20 AAC 25.112. In our judgment, it is also the best P&A method for these wells (see slide 19 of our presentation), as it provides 2000 feet of continuous cement to surface, extending below laterally contiguous confining layers, without compromising the integrity of the existing production casing, which provides an important additional barrier to fluid migration to surface. Because the proposed P&A method complies with the applicable regulation, no variance is needed, and no variance is requested. We hope this clarification aids in your consideration of Meltwater P&A sundry requests. Ty Senden ConocoPhillips Alaska, Inc ATO-676 O: 907-265-1544 C: 907-982-3996 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RE: Docket Number: OTH-22-027 Drillsite 2P Plugging and Abandonment Plan The Alaska Oil and Gas Conservation Commission (AOGCC) on its own motion, pursuant to 20 AAC 25.540, calls a public hearing to address the abandonment of Kuparuk River Unit (KRU) Drillsite 2P(DS-2P), also known as Meltwater. The Meltwater field was initially developed by CPAI in 2002. After development, elevated outer annulus (OA) pressures were observed in ten wells as the result of a reservoir containment event in which miscible injectant (MI) was not confined to the approved injection interval. On November 16, 2021 and July 19, 2022, ConocoPhillips Alaska, Inc. (CPAI) presented to the AOGCC plans to abandon Kuparuk River Unit (KRU) Drillsite 2P (DS-2P), also known as Meltwater. Based on analysis presented by CPAI, DS-2P production backout resulted from hydraulics, facility constraints and water injection; the net production from producing DS-2P was uneconomic for CPAI to produce. The Meltwater field was shut in September 2021 and CPAI proposes full abandonment of the wells. CPAI’s proposal included plans to plug and abandon all nineteen wells on DS-2P by setting three cement plugs in each well: one in the OA, one across the reservoir section, and one across the tubing and inner annulus. The AOGCC questions the adequacy of setting a cement plug in the OA via a down squeeze method as it may not adequately confine hydrocarbon-bearing intervals and the placement and quality of the cement plug cannot be verified. CPAI’s proposed execution plan for the plugging and abandonment of the wells on DS-2P requires waivers from AOGCC’s well plugging requirements per 20 AAC 25.112. Due to concerns regarding loss of confinement and in the interest of the public, a public hearing is required for the AOGCC to consider waivers from 20 AAC 12.112. Additionally, CPAI must demonstrate that the abandonment of DS-2P does not result in waste of the resource. The AOGCC has scheduled a public hearing on this matter for December 8, 2022, at 10:00 a.m. The hearing, which may be changed to full virtual if necessary, 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: 257 622 39#. Anyone who wishes to participate remotely using MS Teams video conference should contact Ms. Carlisle at least two business days before the scheduled public hearing to request an invitation for MS Teams. In addition, written comments 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 December 8, 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 November 30, 2022. Jessie L. Chmielowski Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.09.29 15:29:05 -08'00' From:Carlisle, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Public Hearing Notice, OTH-22-027 (KRU) Date:Monday, October 3, 2022 9:06:14 AM Attachments:OTH-22-027 Public Hearing Notice.pdf Docket Number: OTH-22-027 Drillsite 2P Plugging and Abandonment Plan Samantha Carlisle 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.carlisle@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.carlisle%40alaska.gov Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 mailed 10/3/22 1 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov August 18, 2022 Mr. Greg Hobbs, P.E. Regulatory Engineer, Wells Team ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Docket Number: OTH-22-027 Drillsite 2P Plugging and Abandonment Plan Dear Mr. Hobbs: On November 16, 2021 and July 19, 2022, ConocoPhillips Alaska, Inc. (CPAI) presented to the Alaska Oil and Gas Conservation Commission (AOGCC) plans to abandon Kuparuk River Unit (KRU) Drillsite 2P (DS-2P), also known as Meltwater. Based on analysis presented by CPAI, DS-2P production backout resultedfrom hydraulics, facility constraints and water injection; the net production from producing DS-2P was uneconomic for CPAI to produce. The Meltwater field was shut in September 2021 and CPAI proposes full abandonment of the wells. The Meltwater field was initially developed by CPAI in 2002. After development, elevated outer annulus (OA) pressures were observed in ten wells as the result of a reservoir containment event in which miscible injectant (MI) was not confined to the approved injection interval. CPAI’s proposal included plans to plug and abandon all nineteen wells on DS-2P by setting three cement plugs in each well: one in the OA, one across the reservoir section, and one across the tubing and inner annulus. The AOGCC questions the adequacy of setting a cement plug in the OA via a down squeeze method as it may not adequately confine hydrocarbon-bearing intervals and the placement and quality of the cement plug cannot be verified. CPAI’s proposed execution plan for the plugging and abandonment of the wells on DS-2P requires waivers from AOGCC’s well plugging requirements per 20 AAC 25.112. Due to concerns regarding loss of confinement and in the interest of the public, a public hearing is required for the AOGCC to consider waivers from 20 AAC 12.112. Additionally, CPAI must demonstrate that the abandonment of DS-2P does not result in waste of the resource. If you have any questions, please contact Victoria Loepp at victoria.loepp@alaska.gov or 907-793- 1247. Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner Commissioner Commissioner Daniel Seamount Digitally signed by Daniel Seamount Date: 2022.08.18 12:49:52 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2022.08.18 13:45:16 -08'00' Jeremy Price Digitally signed by Jeremy Price Date: 2022.08.19 08:18:57 -08'00' Docket Number: OTH-22-027 Drillsite 2P Plugging and Abandonment Plan August 18, 2022 Page 2 of 2 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10-days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to 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.