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AIO 021 C
AREA INJECTION ORDER 21C Meltwater Oil Pool Kuparuk River Field 1. December 22, 2017 CPA request to Amend AIO 21B 2. December 31, 2017 Notice of public hearing, affidavit of publication, email distribution, mailings 3. February 8, 2018 Transcript and sign-in sheet 4. February 16, 2018 CPA response to question from the AOGCC at hearing 5. October 18, 2019 CPA request for Admin Approval AIO 21C.001 6. November 2, 2019 CPA request for Admin Approval KRU 2P-434 AIO 21C.002 7. July 29, 2024 CPAI requests for cancellation of AIO 21C.002 (AIO 21C.002 cancellation) 8. August 28, 2024 CPAI requests for cancellation of AIO 21C.001 (AIO 21C.001 cancellation) ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage Alaska 99501 Re: THE APPLICATION OF ) Area Injection Order No. 21C CONOCOPHILLIPS ALASKA, ) Docket No. AIO-17-041 INC. for an amendment authorizing ) the injection of water for enhanced oil ) Kuparuk River Field recovery in the Meltwater Oil Pool, in ) Kuparuk River Unit the Meltwater Participating Area, ) Meltwater Oil Pool Kuparuk River Field, North Slope, ) Alaska ) April 4, 2018 IT APPEARING THAT: 1. By letter dated December 22, 2017, ConocoPhillips Alaska, Inc. (CPAI) requested the Alaska Oil and Gas Conservation Commission (AOGCC) amend Area Injection Order No. 2 1 B (AIO 21B) to allow the injection of water for enhanced oil recovery purposes in the Meltwater Oil Pool (MOP). 2. A notice of public hearing was published on the State of Alaska Online Public Notice web site, the AOGCC web site, and sent to the AOGCC's mail and email distribution lists on December 29, 2017. On December 31, 2017, the notice was published in the Alaska Dispatch News. The hearing was scheduled for February 8, 2018. 3. On February 8, 2018, the public hearing convened. 4. At the end of the February 8, 2018, hearing, the record was left open for 30 days for CPAI to respond to questions asked during the hearing. CPAI submitted the requested information on February 16, 2018. The record closed on March 10, 2018. FINDINGS: The Environmental Protection Agency exempted all aquifers within the existing KRU. 40 CFR 147.102. 2. CO 456A defines the MOP as strata equivalent to those between 6,785 and 6,974 feet measured depth (MD) in well Meltwater North #2A. 3. On August 1, 2001, the AOGCC issued AIO 21, which authorized a water alternating miscible gas injection project in the MOP for the purposes of enhancing oil recovery. 4. Regular production from the MOP commenced in November 2001. Miscible gas injection began in January 2002, and water injection commenced in May 2003. Producing wells initially used miscible injectant (MI) for artificial lift. 5. The initial reservoir pressure for the MOP was approximately 2,400 psi. Injection activity increased reservoir pressure near injection wells to over 4,000 psi; reservoir pressure near shut-in producers reached nearly 3,000 psi. Area Injection Order No 2� April 4, 2018 Page 2 6. CPAI encountered elevated gas pressures while drilling MOP well KRU 2P-441 in March 2002. Beginning in April 2002, CPAI noted elevated outer annulus pressures in MOP development wells. Gas samples taken from outer annuli had chemical signatures consistent with MI. CPAI initially suspected MI gas used for artificial lift was migrating into the outer annuli, possibly through leaking, threaded casing connections. After identifying elevated outer annulus pressures in MOP wells, CPAI initiated an annulus -monitoring program and attempted periodic annulus pressure bleeds. Since 2003, CPAI has provided periodic updates of monitoring and diagnostic efforts to AOGCC. 9. Water injection into the MOP ceased in October 2009 due to water supply line corrosion concerns. CPAI converted existing MOP water -injection wells to MI injection or shut them in. CPAI no longer uses water injection, other than for short term diagnostic purposes. 10. Using proprietary 4D seismic evaluation, CPAI identified a potential vertical migration mechanism from the MOP that allowed injected fluids to escape from the MOP and enter shallower strata. 11. During April 2012, CPAI reduced the injection -to -withdrawal ratio to ensure confinement of injected fluids to the MOP. Outer annuli pressures subsequently declined. In August 2012, CPAI restricted MI injection pressure to ensure that sand - face injection pressure remains less than 3,400 psi. 12. On October 4, 2012, AOGCC issued Administrative Approval AIO 21.001 allowing continued MI injection into the MOP subject to several conditions, including: daily recording of well pressures, monthly reporting of all MOP wells, and pressure restrictions on the outer annuli of all wells. 13. On January 29, 2013, the AOGCC issued AIO 21A, which prohibited water injection in the MOP. 14. On October 8, 2015, the AOGCC issued AIO 21B, which allowed for water injection in the MOP for purposes other than EOR. 15. CPAI requests AOGCC revise AIO 21B to allow water injection for EOR purposes in the MOP. 16. As noted in Finding 5 above previous EOR injection in the MOP was done at pressures much higher than the original pool pressure and led to a loss of containment of the injected fluids. It is believed that water, being an incompressible fluid, resulted in fractures forming in the pool and confining layer and this led to miscible injectant escaping. 17. After determining the mechanism that allowed for injected fluids to escape confinement CPAI reduced the injection/withdrawal ratio so as to lower the reservoir pressure. It also reduced the sand -face injection pressure limit to 3,400 psi, which is below the fracture propagation pressure. 18. Since the injection/withdrawal ratio and sand -face injection pressure were reduced the outer annulus pressures on the wells in the area have declined and the frequency of bleeds has decreased. The composition of gas bled from the outer annuli shows the gas to be getting leaner over time. All these factors indicate that the fractures that Area Injection Order No 2� April 4, 2018 Page 3 allowed MI to escape from the MOP have closed and injected fluids are now being contained within the MOP. 19. The producing gas oil ratio (GOR) for the MOP has increased approximately 10 fold since water injection ceased in 2009 and is now seven times higher than the field wide average and about four times higher than any other pool in the field. 20. A shut in test performed at the MOP in the summer of 2017 estimated that the high GOR production coming from the MOP was causing 900 BOPD to be backed out from other areas of the KRU. 21. Low liquid flow rates present a risk of the flowline from Meltwater freezing during the winter. If water injection at Meltwater is resumed water can be blended from the water supply line with production from the wells to increase the liquid flowrate in the flowline to prevent freezing. 22. Re-establishing water injection at Meltwater is expected to increase ultimate recovery over continued gas injection by 1-2 MMBO. Ultimate recovery may further increase if the water injection results in a decrease in the producing GOR and leads to the MOP being a more attractive target for additional drilling. 23. On August 9, 2017, the AOGCC issued AIO 2113.002, which authorized a water injectivity test for the KRU 2P-429 well to evaluate the feasibility of lower pressure, below the formation's parting pressure, water injection in the MOP as an EOR project. This test indicated that sufficient volumes of water could be injected at pressures below the sand -face injection pressure limit to be an effective EOR proj ect and showed no indications of loss of containment. CONCLUSIONS: 1. Re-establishing water injection in the MOP should result in improved ultimate recovery from the MOP due to reduction of the producing GOR making production from the MOP more competitive with the rest of the KRU. It should also improve production from other parts of the field due to decreasing the amount of oil production that is backed out because of the high gas production from the MOP. 2. Water injection below the sand -face injection pressure limit of 3,400 psig should ensure injected fluids are contained within the MOP. NOW, THEREFORE, IT IS ORDERED THAT AIO 21, AIO 21 A, and AIO 2 1 B and all associated administrative approvals, except for AIO 2113.001, are hereby revoked and replaced by this order. All information related to AIO 21, AIO 21A, and AIO 2 1 B and their associated administrative approvals is hereby incorporated by reference into the record for this order. The following rules, in addition to statewide requirements under 20 AAC 25 (to the extent not superseded by these rules), govern Class rI enhanced oil recovery injection operations in the affected area described below: Area Injection Order No 2, April 4, 2018 Umiat Meridian ( Page 4 Township Range Section T8N R7E Sections 1 through 36: All State Lands Rule 1 Authorized Infection Strata for Enhanced Recovery (Source: AIO 21) Within the affected area, fluids appropriate for enhanced recovery may be injected for purposes of pressure maintenance and enhanced recovery into strata that are common to, and correlate with, the interval between 6,785' and 6,974' MD in well Meltwater North #2A. Rule 2 Meltwater Oil Pool Wells (Source: AIO 21B) For any new well drilling surface hole in the affected area: a. A well site survey in accordance with 20 AAC 25.061(a) will be required; and b. Mud logs, gamma ray logs, porosity and resistivity logs will be required from the base of the conductor to total depth. Rule 3 Monitoring the Tubing -Casing Annulus Pressure Variations (Source: AIO 21, AIO 21.001) The tubing -casing annulus pressure and injection rate of each injection well must be checked at least weekly to confirm continued mechanical integrity. The operator shall record wellhead pressures and injection rates daily. The operator shall limit the outer annulus pressure to 1000 psi. Rule 4 Demonstration of Tubing -Casing Annulus Mechanical Integrity (Source: Revised this order) The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. An AOGCC-witnessed mechanical integrity test (MIT) must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, and rate) have stabilized and every 2 years thereafter. MIT's must be conducted in accordance with the current revision of AOGCC Industry Guidance Bulletin — "Mechanical Integrity Testing" and done to a test pressure equal to the maximum anticipated surface injection pressure. The AOGCC must be notified, following the procedures in the current revision of AOGCC Industry Guidance Bulletin — "Test Witness Notification", at least 48 hours in advance to enable a representative to witness a MIT. The MIT report (AOGCC Form 10-426) must be provided to AOGCC no later than the 5`h calendar day of the month following the testing. Test results must be readily available for AOGCC inspection upon request. Rule 5 Notification of Improper Class II Infection (Source: AIO 21B) Injection of fluids other than those listed in Rule 8 without prior authorization is improper Class II injection. Upon discovery of such an event, the operator must immediately notify the AOGCC, provide details of the operation, and propose actions to prevent recurrence. Area Injection Order No 2, Page 5 April 4, 2018 Notification to AOGCC does not relieve the operator of the notification requirements of any other State or Federal agency. Rule 6 Well Integrity and Confinement (Source: AIO 21A) Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rate, operating pressure observation, test, survey, log, or other evidence, the operator shall immediately notify the AOGCC and obtain permission for continued operation of the well. A corrective action plan shall be provided for AOGCC review and approval prior to further action being taken. The operator will also consult with the AOGCC about the need to shut in all wells in the MOP. Rule 7 Authorized Infection Pressure (Source: AID 21A.004) Injection pressures must be maintained at or below 3,400 psig at the reservoir sand -face. Rule 8 Authorized Fluids for Iniection (Source: Revised this order) Fluids authorized for injection are: a. Miscible injectant; b. Dry gas provided by the Kuparuk River Unit; c. Tracer survey fluid to monitor reservoir performance; d. Fluids injected for stimulation purposes per 20 AAC 25.280(a)(2); e. Glycol from hydro -tests and freeze protection; f. Diesel used for freeze protection; g. Methanol used for freeze protection; h. Standard oilfield chemicals (corrosion and scale inhibitors, defoamers, emulsion breakers, etc.); i. Beaufort Sea water; and j. KRU produced water. Any other fluids, or uses for the above fluids, shall be approved in advance by separate action based upon proof of compatibility with the reservoir and formation fluids. Rule 9 Performance Reporting (Source: AIO 21M The operator shall submit to AOGCC an annual synopsis of the surveillance, monitoring, and development initiatives completed during the previous year that pertain to the confinement of the injected fluids within the MOP together with the Meltwater Annual Surveillance Report. The annual surveillance report will be required by April 1 of each year. The report shall include, but is not limited to, the following: a. progress of the enhanced recovery project and reservoir management summary including engineering and geological parameters; b. reservoir voidage balance by month of produced and injected fluids; c. analysis of reservoir pressure surveys within the pool; d. results and, where appropriate, analysis of production and injection log surveys, tracer surveys and observation well data or surveys; e. assessment of fracture propagation into adjacent confining intervals; f. summary of MIT results; Area Injection Order No 2i April 4, 2018 Page 6 g. summary of results of inner and outer annulus monitoring for all production wells, injection wells, and any wells that are not cemented across the Meltwater Oil Pool and are located within a''/4 -mile radius of a Meltwater injector; h. results of any special monitoring; i. reservoir surveillance plans for the next year; and j. future development plans. Rule 10 Administrative Action (Source: AIO 21A) Upon proper application, or its own motion, and unless notice and public hearing are otherwise required, the AOGCC may administratively waive the requirements of any rule stated herein or administratively amend this order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement into freshwater. Rule 11 Expiration Date (Revoked this order) Done at Anchorage, Alaska and dated April 4, 2018. Hollis S. French Daniel T. eamount, Jr. Chair, Commissioner Commissioner TION AND As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10•days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does no fall on a weekend or state holiday. Colombie, Jody J (DOA) From: Colombie, Jody 1 (DOA) Sent: Thursday, April 05, 2018 10:40 AM To: DOA AOGCC Prudhoe Bay; Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha 1 (DOA); Colombia, Jody J (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Loepp, Victoria T (DOA); Mcphee, Megan S (DOA); Rixse, Melvin G (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alicia Showalter, Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Lewallen; Anna Raff; Barbara F Fullmer, bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Bonnie Bailey, Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cody Gauer; Cody Terrell; Colleen Miller, Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer, Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock, Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hurst, Rona D (DNR); Hyun, lames J (DNR); Jacki Rose; Jason Brune; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); Jon Goltz; Chmielowski, Josef (DNR); Joshua Stephen; Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller, Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt, Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; Motteram, Luke A; Mueller, Marta R (DNR); Nathaniel Herz, knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Ryan Gross; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Sofia Laughland; Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R, Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer, Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams, Casey Sullivan; Corey Munk, D. McCraine; Don Shaw, Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck, Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: AIO 21C (CPA) Attachments: aio2lc.pdf Please see attached. Bernie Karl M Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 Re: THE APPLICATION OF ) Area Injection Order No. 21C CONOCOPHILLIPS ALASKA, ) Docket No. AIO-17-041 INC. for an amendment authorizing ) the injection of water for enhanced oil ) Kuparuk River Field recovery in the Meltwater Oil Pool, in ) Kuparuk River Unit the Meltwater Participating Area, ) Meltwater Oil Pool Kuparuk River Field, North Slope, ) Alaska Jody J. Co(ombie .AOGCC Syecia(.Assistant .A(aska Oi(andGas Conservation Commission 333 West 7" .Avenue -Anchorage,.A(aska 99507 Office: (907) 793-1221 -Tax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or jodv. colombie@alaska aov. Tlll: S"I'ATI: "ALASKA GOVERNOR MIC1-IALL t. DUNLFAXY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 21C.001 Mr. Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-033 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Request for administrative approval to allow well 2P-427 (PTD 2020180) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2P-427 (PTD 2020180) Kuparuk River Field Meltwater Oil Pool Dear Mr. Byrne: By letter dated October 18, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 021C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on December 27, 2018 while the well was injecting gas. CPAI confirmed the pressure communication to gas over the AOGCC approved 30 day gas monitoring period. CPAI WAG'ed the well from gas to water for another 30 day monitoring period in which there were no further signs of pressure communication. The well passed a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 1, 2019 which indicates that 2P-427 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 21C.001 October 23, 2019 Page 2 of 2 AOGCC's approval to continue water iniection only in KRU 2P-427 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated October 23, 2019.,0 //signature on file// //signature on file// //signature on file// °` e Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Chair, Commissioner 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. THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 21C.001 Mr. Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-19-033 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.claska.gov Request for administrative approval to allow well 2P-427 (PTD 2020180) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2P-427 (PTD 2020180) Kuparuk River Field Meltwater Oil Pool Dear Mr. Byrne: By letter dated October 18, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 021C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on December 27, 2018 while the well was injecting gas. CPAI confirmed the pressure communication to gas over the AOGCC approved 30 day gas monitoring period. CPAI WAG'ed the well from gas to water for another 30 day monitoring period in which there were no further signs of pressure communication. The well passed a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 1, 2019 which indicates that 2P-427 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 21C.001 October 23, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in KRU 2P-427 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure to 1000 psi; 5. CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; 6. After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and 7. The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. DONE at Anchorage, Alaska and dated October 23, 2019. �m 1Xc�� Price Daniel T. Seamount, Jr. J sie�ielowski Chair, Commissioner Commissioner Commissioner AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 21C.001 CANCELATION Ms. Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-24-025 Request to cancel Area Injection Order (AIO) 21C.001 Kuparuk River Unit (KRU) 2P-427 (PTD 202-018), Meltwater Oil Pool Dear Ms. Bronga: By letter dated August 28, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) AIO 21C.001. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to cancel the AA. CPAI reported a potential tubing by inner annulus pressure communication to AOGCC on December 27, 2018, while the well was injecting gas. On October 23, 2019, AOGCC issued AIO 21C.001. AOGCC determined that water only injection could safely continue if CPAI complied with the restrictive conditions set out in the AA. CPAI has suspended the well under Sundry 324-192 and on August 9, 2024, completed a passing state-witnessed cement plug verification and mechanical integrity test of the tubing. AA AIO 21C.001 is hereby CANCELED. DONE at Anchorage, Alaska and dated August 29, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.09.05 21:54:37 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.09.06 09:39:55 -08'00' AIO 21C.001 Cancellation September 6, 2024 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. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 21C.001 Cancellation (CPAI) Date:Friday, September 6, 2024 9:47:23 AM Attachments:aio21c.001 cancellation.pdf Docket Number: AIO-24-025 Request to cancel Area Injection Order (AIO) 21C.001 Kuparuk River Unit (KRU) 2P-427 (PTD 2020180), Meltwater Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Alaska Oil and Gas Conservation Commission ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 21C.002 Mr. Dusty Freeborn Well Integrity Supervisor ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 333 west Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov Re: Docket Number: AIO-19-034 Request for administrative approval to allow well 2P-434 (PTD 2031530) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2P-434 (PTD 2031530) Kuparuk River Field Meltwater Oil Pool Dear Mr. Freeborn: By letter dated November 2, 2019, ConocoPhillips Alaska, Inc. (CPAI) requested administrative approval to continue water only injection in the subject well. In accordance with Rule 10 of Area Injection Order (AIO) 021C.000, the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI's request for administrative approval to continue water only injection in the subject well. CPAI reported a potential tubing (T) by Inner Annulus (IA) pressure communication to AOGCC on April 17, 2018 while the well was shut in. CPAI WAG'ed the well from gas to water for a 30 - day monitoring period in which there were no further signs of pressure communication. The well passed a state witnessed Mechanical Integrity Test of the Inner Annulus (MITIA) on October 14, 2019 which indicates that 2P-434 exhibits at least two competent barriers to the release of well pressure. The well does not exhibit signs of pressure communication while on water injection. Accordingly, the AOGCC believes that the well's condition does not compromise overall well integrity so as to threaten human safety or the environment. AIO 21C.002 November 5, 2019 Page 2 of 2 AOGCC's approval to continue water injection only in KRU 2P-434 is conditioned upon the following: 1. CPAI shall record wellhead pressures and injection rate daily; 2. CPAI shall submit to the AOGCC a monthly report of well pressures, injection rates, and pressure bleeds for all annuli. Bleeds to be flagged on the report; 3. CPAI shall perform a mechanical integrity test of the inner annulus every 2 years to the greater of the maximum anticipated injection pressure or 0.25 x packer TVD, but not less than 1500 psi; 4. CPAI shall limit the well's IA operating pressure to 2000 psi and the OA operating pressure Q 7 to 1000 psi; CPAI shall immediately shut in the well and notify the AOGCC if there is any change in the well's mechanical condition; After well shut in due to a change in the well's mechanical condition, AOGCC approval shall be required to restart injection; and The next required MIT is to be before or during the month of August 2020. This is to align with the agreed upon CPAI Underground Injection Control MIT permanent test schedule for pad testing. lor.=yz. DONE at Anchorage, Alaska and dated November 5, 2019. J erice Je "ie L. Chmielowski Chair, mmissioner Commissioner AND APPEAL As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time 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 he the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. Carlisle, Samantha J (CED) From: Carlisle, Samantha J (CED) Sent: Tuesday, November 5, 2019 1:52 PM To: 'AOGCC-Public-Notices' Subject: AIO 21C.002 Attachments: aio21 c.002.pdf Docket Number: AIO-19-034 Request for administrative approval to allow well 2P-434 (PTD 2031530) to be online in water only injection service with a known tubing by inner annulus communication. Kuparuk River Unit (KRU) 2P-434 (PTD 2031530) Kuparuk River Field Meltwater Oil Pool Samantha Carlisle .Executive Secretary III Alaska Oil and Gas Conservation Commission 333 West 711� Avenue Anchorage, ATS 99501 (907) 793-1223 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review. use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, aud, so that. the AOGCC is aware of the mistake in sending it to you, contact Samantha Carlisle at (907) 793-1.223 or Samartha.Carlislei<i�alask_x.eov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov ADMINISTRATIVE APPROVAL AREA INJECTION ORDER NO. 21C.002 CANCELLATION August 8, 2024 Ms. Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Re: Docket Number: AIO-24-022 Request to cancel Area Injection Order (AIO) 21C.002 Kuparuk River Unit (KRU) 2P-434 (PTD 2031530), Meltwater Oil Pool Dear Ms. Bronga: By letter dated July 29, 2024, ConocoPhillips Alaska, Inc. (CPAI) requested cancellation of administrative approval (AA) AIO 21C.002. In accordance with 20 AAC 25.556(d), the Alaska Oil and Gas Conservation Commission (AOGCC) hereby GRANTS CPAI’s request to cancel the AA. CPAI reported a potential tubing by inner annulus pressure communication to AOGCC on April 17, 2018, while the well was shut in. On November 5, 2019, AOGCC issued AIO 21C.002. AOGCC determined that water only injection could safely continue if CPAI complied with the restrictive conditions set out in the AA. CPAI has suspended the well under Sundry 323-549 and on July 12, 2024, completed a passing state-witnessed cement plug verification and mechanical integrity test of the tubing. AA AIO 21C.002 is hereby CANCELLED. DONE at Anchorage, Alaska and dated August 8, 2024. Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.08.08 14:14:14 -08'00' Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.08.08 14:54:48 -08'00' AIO 21C.002 Cancellation August 8, 2024 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. From:Coldiron, Samantha J (OGC) To:AOGCC_Public_Notices Subject:[AOGCC_Public_Notices] Area Injection Order 21C.002 cancellation (CPAI) Date:Friday, August 9, 2024 7:56:21 AM Attachments:aio21c.002 cancellation.pdf Docket Number: AIO-24-022 Request to cancel Area Injection Order (AIO) 21C.002 Kuparuk River Unit (KRU) 2P-434 (PTD 2031530), Meltwater Oil Pool Samantha Coldiron AOGCC Special Assistant Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 (907) 793-1223 __________________________________ List Name: AOGCC_Public_Notices@list.state.ak.us You subscribed as: samantha.coldiron@alaska.gov Unsubscribe at: https://list.state.ak.us/mailman/options/aogcc_public_notices/samantha.coldiron%40alaska.go v INDEXES 8 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 August 28, 2024 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. requests the cancellation of Administrative Approval AIO 21C.001 for Kuparuk service well 2P-427 (PTD 202-018).AIO 21C.001 was approved October 18, 2019, allowing continued water only injection due to TxIA on gas injection. KRU 2P-427 was recently suspended (sundry 324-192 ) which included setting a CIBP and dump bailing cement on top. The state witnessed tag of TOC and MIT-T to 1500 psi was completed on 8/9/2024. As such, AIO 21C.001 is no longer relevant and CPAI request that the AIO be cancelled. Please contact Jaime Bronga at 907-265-1053 if you have any questions. Sincerely, Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. By Samantha Coldiron at 8:03 am, Aug 29, 2024 Digitally signed by Jaime Bronga DN: OU=Conoco Phillips Alaska, CN=Jaime Bronga, E=jaime.bronga@conocophillips.com Reason: I am the author of this document Location: Date: 2024.08.28 15:26:31-08'00' Foxit PDF Editor Version: 13.0.0 Jaime Bronga 7 P.O. BOX 100360 ANCHORAGE, ALASKA 99510-0360 July 29, 2024 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski, ConocoPhillips Alaska, Inc. requests the cancellation of Administrative Approval AIO 21C.002 for Kuparuk service well 2P-434 (PTD 203-153). AIO 2C.002 was approved November 2, 2019, allowing continued water only injection due to TxIA on gas injection. KRU 2P-434 was recently suspended (sundry 323-549) which included setting a CIBP and dump bailing cement on top. The state witnessed tag of TOC and MIT-T to 1500 psi was completed on 7/12/2024. As such, AIO 21C.002 is no longer relevant and CPAI request that the AIO be cancelled. Please contact Jaime Bronga at 907-265-1053 if you have any questions. Sincerely, Jaime Bronga Well Integrity Specialist ConocoPhillips Alaska, Inc. Digitally signed by Jaime Bronga DN: OU=Conoco Phillips Alaska, CN=Jaime Bronga, E=jaime.bronga@conocophillips.com Reason: I am the author of this document Location: Date: 2024.07.29 16:08:00-08'00' Foxit PDF Editor Version: 13.0.0 Jaime Bronga l•1 November 2, 2019 Commissioner Jessie Chmielowski Alaska Oil & Gas Conservation Commission 333 West 7`h Avenue, Suite 100 Anchorage, AK 99501 Commissioner Chmielowski: RECEIVED NOV 0 5 P019 AOGCC ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 21 C, Rule 10, to apply for administrative approval to allow KRU injection well 2P-434 (PTD 203-153) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Dusty Freeborn / Jan Byrne Well Integrity Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 WELLS TEAM Conooa�'®�s ConocoPhillips Alaska, Inc. Kuparuk River Field, Meltwater Oil Pool 2P-434 (PTD# 203-153) Technical Justification for Administrative Action Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 21 C, Rule 10, to continue water only injection for Kuparuk injection well 2P-434 (PTD 203-153). The well displays annular communication only when the well is in gas injection service. Well History and Status Meltwater injection well 2P-434 (PTD# 203-153) was drilled and completed on Jan 1, 2004 as a water alternating gas (WAG) enhanced oil recovery (EOR) service well. It was placed on produced water injection in February 2004 and passed a subsequent state witness mechanical integrity test (MIT). The well was operated with WAG cycles until August 2007 when it was shut in. The well was returned to gas service in November 2012 and remained on gas cycles until July of 2015 when it was shut in. April 2018 the well was reported to the AOGCC with a suspected gas only tubing by inner annulus leak while shut in. The well returned to injection early October 2019 after water injection was restored to 2P -Pad. The well passed a AOGCC witnessed MIT -IA to 3200 psi on the 1411' of October 2019 and has since shown no indications of tubing by inner annulus communication while on water injection. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection. However, currently the well exhibits no indications of TxIA communication while on water injection, therefore ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. Barrier and Hazard Evaluation Tubing. The 3-1/2", 9.3#, L-80 tubing has integrity to Baker seal assembly at 5538' MD (5141' TVD), based on the passing AOGCC witnessed MITIA completed on the 14t1i of Oct 2019 and historic pressure trends. Production casing: The 7", 26#, L-80 production casing has an internal yield pressure rating of 7240 psi has integrity to the Baker seal assembly at 5538' MD (5141' TVD) based upon historic pressure trends and the above-mentioned MIT -IA. Surface casing: The 9-5/8", 409, L-80 surface casing with an internal yield pressure rating of 5750 psi set at 2421' MD (2356' TVD) has an open OA shoe however, has historically held elevated pressure showing casing integrity at that time. Primary barrier: The primary barrier to prevent a release from the hydrocarbon producing formation in this well is the production tubing. Well Integrity Compliance Specialist 11/2/2019 Second barrier: The secondary barrier to prevent a release from the hydrocarbon producing formation in this well is the production casing envelope should the production tubing fail. Monitoring Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 -years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set the month of August 2020 to align the AOGCC biennial AA witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity Compliance Specialist 11/2/2019 KUP INJ WELLNAME 21S-434 WELLBORE 2P-434 f`OIl000P11llIp5 lWellAttribues MazAngledMD TD Alaska.InC. Bad Hama weuWre PPInM1 wNIWre sYtoa Irl MO mNBI actehn mKa) MELTWATER SOiW209fi]W INJ 8.19 4,183.83 8030.0 HUS (pp.) 9.M Ena Dale MI Relea e Dae S56V�WRDP I-detWOn 33. 9th 12IS2003 V�'YN3%B e. QIAM Last Tag Veracaeopemuz(ecNe9 Mutelbn Depth MK8) End nate I Wenome la¢tMWB,, Last Ta9:RKe 5,913.0 6120801] 2R-034 ippmven --------- ---- Last Rev Reason Annotation End Data wetlbara Wsl raW ay WWOEfl: D.3 Rev Reason: Pulled 2.75" CA -2 Plug 8/22/2019 2PA34 zemhaej Casing Strings Caelnq 0-1p11on 00(n) mpn) Top(m(B) Se1GePIM1(tIKm Set Depth LIV0)... NeLen 11... Gwtla 1p Thread CONDUCTOR 16 1506 28.0 108.0 1084 62.50 H-40 WELDED C.",Vescription Do (in) 11(i.) Tap Idea) Set Gep2 MKB) Set Depth ITV01... Wlrt.e. a... Glade Top ThreM SURFACE 95M 883 28.1 2,421.4 2,356.2 40.00 L-80 BTC Casing Gezcrip[an DG(Ird 10(n1 Toppoes) Set Depth MI Set Depth (NB- tvEm(L.. Grade Top T4ree1 PRODUCTION ] 6.28 25.5 5,711.0 5,295.7 26.00 L-80 BTCMD Ging De¢cNpton 00(.rl hoped Top(dXB) Ser Deplh(hK9) Set Depth (PRII... Wt,Len IT.. Grade Tep Thmd LINER 3112 299 5,524.8 6,025.0 5,577.7 9.30 L-80 SLHT Get e Liner portage Nominal lG rop lnKal TOPIrvD)1290 rop l26.2 hem Da com (In) 5,524.8 5,129.0 26.20 PACKER BAKER ZXP LINER PACKER 4370 5,543.7 5,145.9 25 RS PACKOFF SEAL NIPPLE 4.2505,546.4 5,1484 .26 BAKER LEXLOCK LINER HANGER 4,410 CONWCTOR 2WOs0 5,556.0 5,15].0 26.28 BAKER 80-00 SEAL BORE EXT 4.000 t 55]4.9 5,1]39 26.33 ING XO TKC BUSHING 3000 NIPPIE:,93.6 Tubing Strings Tubing Deecription Shing Ma... 10 (nl Top InKG) Sel DeplM1 (X.. Sel Depth WI IStth Gare Top Conneatlon TUBING 3112 2.99 23.3 5,95.1 5,1]4.1 9.30 L-80 EUE-bre Completion Details Toplrvo) ToPlnu NcmIral I I Top RISE) LIES) I.) Item Dec com mdrd 23.3 23,3 0.00 HANGER FMC GEN V TUBING HANGER 3.5W 499.8 499.8 0.65 NIPPLE CAMCO DS LANDING NIPPLE 28]5 sVRFACF: a1¢me- SSOB1 5,114.0 26.16 EEVE BAKER CMU SLIDING SLEEVE 2.813 (Opened 489H8. Ra -dared 41N11 8) 7.524.1 =128.4 26.20 NIPPLE BAMCO D NIPPLE 2.750 5,5372 5.140.1 26.23 LOCATOR BAKERG-22LOCATOR 3.000 5538.4 5,1412 26.24 BEALASSY BAKER 80-00 SEAL ASSY 3.000 DAs uFr; s,Ssp Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) Top tNol Top tram Top (ARB)Inxel l'1 9m com R,,,, Dam m Oral 5,882. 5,449.0 26.01 FISH HEM TOOLSAVERBHOKEAFTERFIRING3RDGUN 1I1I2004 LEAVING THE 20' GUN AND SAFEADAPTER IN THE 11 HOLE (24.5' aLEEVE.. .1 perforations B Slots Sher Den NIPPLE: AS2A1 To57 ahn MKB) TOP nVDI MKBI Blm (IV01 (N(GI LinkM Zone pale (sh . I Type Co. 5] .0 5,]]2.0 5,296.6 5,350.3 Tom, 2Pi34 1I1I2004 6.0 WERE Pd, DP; deg Phase. Phase. ranegm Orientation h rim WCATOR:s53Z2 5,780.0 5.784.0 5,35].5 5,351.1 T-3, 2P-434 11 BO PERE 25 -HSI) EJ, DP; W the phase, random orientation 11 1 5,790.0 5,]94.0 5,3fi8.4 5,3]0.0 Tom, 2P-034 1/18004 6.011ER1 2.5HBO PJ, OR; 60 deg phase, random orientation Mandrel Inserts a1 .SALPasY;5.99A en N Tap MKB) Top RVD) (INS) Make MMeI 001in) Sere Valw Type Deep Type Pon She (in) TRO Run (p¢il Run Dale Com 5.459.1 5,0]0.0 UAMUU KBG-2- 1 GASLIFT pMY BTM 0.00 0.0 11l]8005 9 Notes: General 8 Safety End Dam AnrsrMbn ]12]8W9NOTE: ZONESNOTLOADED INTO WELLVI EW YET ]1288009 NOTE:WAN, ED OA: PRESSURE CHARGING FROMRESERVOIR 11838010 NOTE: View SChemaBC./Alaska Sche,hrhe O PR9WC3KIN1$SET1.0- IPERF:A,]t2M.M11- IBm1. A3E0.0a1t&io- IPERF; A]aD.Ofi,]ea.0� FISH: 5.6920 VNEN: 5,534.Ba,OLO� Annular Communication Surveillance Well Name: 2P-434 Start Date: 4 -Aug -2019 Days: 90 End Date: 2 -Nov -2019 Refresh 4500 3GO Injection Rate Summary Pressure Summary 4000 3500 170 25DD 150 20QQ 0 130 w yr R 2500 w a m v a 75CO 2000 110 0 1500 b � t u 1000 dl n 500 100D 90 M 500 'n 70 0 ¢¢ a a a¢ a a a a 9.9 n n J9 9 c? 00 0 0 0 a o o 0 a 50 C i� O m lia ck 1N � N � (.l 6 6 ri ti N Q 0,+ 0, 0, 0{+ e-1 N N ^ •1 N (4` pp so oa m on o w oo n n n n n. n n a n n is G C u Yi 0 5 —DG1 ;� MGI —PWI - =--SAN —BLP➢ D O ¢ a¢¢¢ O 4 o O q 0 P 9 1 o Z VS 1¢1 y� N til q1 TI (n iil CI N N W N Q 9 Ri O+ ti N N N6 N .N- —WHP —IAP —OAP —WHT 4500 Injection Rate Summary 4000 3500 2E 3000 0 R 2500 m 2000 0 1500 t u 1000 500 'n ¢¢ a a a¢ a a a a 9.9 n n J9 9 c? 00 0 0 0 a o o 0 a C i� O m lia ck 1N � N � (.l 6 6 ri ti N Q ri e-1 N N ^ •1 N (4` r9 N aY —DG1 MGI —PWI - =--SAN —BLP➢ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to jim.reoaCalalaskaaow AOGCC.Insoeclors(aillaskaaovv phoebe. brooks(@alaska.aov OPERATOR: ConomPhillips Alaska Inc, FIELD/UNIT/PAD: Kupawk/KRU/2P Pad DATE: 10/14/19 OPERATOR REP: Beck / Green AOGCC REP: Lou Laubensteln PTD chris.wallacerrDalaska aov Well 2P-434 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 0= Other (describe In Notes) PTD 2031530 Type Inj W Tubing 1000 1000 1000 1000 O = Other (describe In nates) Type Test P Packer ND 5141 BBL Pump 2.2 IA 100 3200 3070 3050 Interval O Test psi 2900 BBL Return 2.1 OA 700 710 710 710 Result P Notes: MITIA to maximum surface Injection pressure perA10 21C and Sundry 111318451 conversion from GINJ to WAG injection Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Tubing Type Test Packer ND BHBL IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min, 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBI -Pump IA Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W=Water P=Pressure Test I=Initial Test P=Paas G=Gas 0= Other (describe In Notes) 4=Four Year Cycle F=Fall 5=Slurry V=Requiretl- h Variance I -Inconclusive 1= Industrial Wes(exaler O = Other (describe In nates) N = Not Injecting Form 10-426 (Revised 01/2017) MIT KRU 21`-03410-14-19.xlsx 5 October 18, 2019 RECEIVED Commissioner Jessie Chmielowski OCT 2 2 2019 Alaska Oil & Gas Conservation Commission 333 West 7' Avenue, Suite 100 A ��+CC Anchorage, AK 99501 A Commissioner Chmielowski: ConocoPhillips Alaska, Inc. presents the attached proposal per AIO 21 C, Rule 10, to apply for administrative approval to allow KRU injection well 2P-427 (PTD 202-018) to remain in water only injection service. Currently the well has known tubing by inner annulus communication only while on gas injection. If you need additional information, please contact us at your convenience. Sincerely, Jan Byrne / Dusty Freeborn Well Integrity Supervisor ConocoPhillips Alaska, Inc. Office phone: (907) 659-7224 WELLS TEAM ConocoPhillips Alaska, Inc. Kuparuk Well 2P-427 (PTD# 202-018) Technical Justification for Administrative Relief Request Purpose ConocoPhillips Alaska, Inc. proposes that the AOGCC approve this Administrative Relief request as per Area Injection Order 21 C, Rule 10, to continue water only injection for Kuparuk injection well 2P-427 (PTD 202-018). The well displays annular communication only when the well is in gas injection service. Well History and Status KRU well 2P-427 was drilled and completed in October of 2002 as a development well and converted to a service well in March 2005. 2P-427 was initially reported to the Commission on December 27th, 2018, for suspected tubing by inner annulus (TxIA) communication while in gas injection service and communication was confirmed during the following monitor period. The well was brought on water injection September 19th, 2019 after water injection was restored to the drill site. The well has shown no signs of TxIA communication while on water injection. The well passed a SW MITIA to 3,200 psi on October 1St, 2019. ConocoPhillips intends to pursue repairs if tubing by inner annulus communication develops while on water injection. However, currently the well exhibits no indications of TxIA communication while on water injection, therefore ConocoPhillips requests an administrative approval (AA) which will allow for continued injection of water only. Barrier and Hazard Evaluation With only water injection, this well has all the barriers of a normal injection well Tubing: The 3-1/2", 9.3 lb., L-80 tubing has integrity to the seal assembly at 9,532' MD (5,456' TVD) based on a passing State Witnessed MIT -IA to 3,200 psi on October 1St, 2019 and TIO trends. Production casing: The 5.5", 15.5 lb., L-80, production casing has integrity to the packer at 9,532' MD (5,456' TVD) based on the aforementioned MIT -IA and TIO trends. Surface casing: The 7-5/8", 29.7 lb., L-80 surface casing has integrity to the set depth at 3,029' MD (2,380' TVD) based on TIO trends. The 7-5/8" has an internal yield pressure rating of 6,890 psi. Primary barrier: The primary barrier to prevent a release from the well and provide zonal isolation is the tubing and packer. Secondary barrier: The production casing is the secondary barrier should the tubing fail. Tertiary barrier: The surface casing will act as a third barrier in the unlikely event that primary and secondary barriers lose integrity. Well Integrity and Compliance Specialist 10/19/2019 Monitoring: Each well is monitored daily for wellhead pressure changes. Should leaks develop in the tubing or production casing above the surface casing shoe it will be noted during the daily monitoring process. Any pressure trends that indicate annular communication require investigation, Commission notification, and corrective action, up to and including a shut-in of the well. T/IO plots are compiled, reviewed, and submitted to the AOGCC on a monthly basis. Proposed Operating and Monitoring Plan 1. Well will be used for water only injection (no MI or gas injection allowed); 2. Perform a passing MITIA every 2 -years to maximum anticipated injection pressure; 3. Allow operating IA pressure up to 2000 psi, operating OA pressure up to 1000 psi; 4. Submit monthly reports of daily tubing, IA & OA pressures, injection volumes and pressure bleeds for all annuli; 5. Shut-in the well should diagnostic testing or injection rates and pressures indicate further problems with appropriate notification to the AOGCC. 6. Anniversary date to be set the month of August 2020 to align the AOGCC biennial AA witnessed testing with the UIC MIT permanent 4 -year scheduled pad testing. Well Integrity and Compliance Specialist 10/19/2019 2 KUP INJ WELLNAME 2P-427 WELLBORE 2P427 ConoeoPhillips Weu Attributes Max Ang)e&MD TD gill T In'. iieltl Name Wellbore FP00Wl ll - se., ndl°) 1 ahn I11KB) MELTWATER 501032040800 INJ .34 10,300.49 10,4112.0 Commem RR(pp.) Gate MnoWe n Entl ga@ KBGr41fl) PoB Raises¢Oete SSSV: VJRDP Led W0: 3].10 &192002 9F>ZT, 1SI13r1%9 ):4&19 PN Last lag VeM1'ulaNernaY[(etlue9 on OepIh(1KG)) alloon Motl ay .............. ..........._.Casing l:o. .....- 2/[Gae 10Mtl,03018 zem1b8aet jLeM Tag: RKB (Est. 29 M 0 121 2-02)W Last Rev Reason Mnolallon Entl Wte WNIOon LeMMOJ Sy RANGER: gS.T Rev Reason: UptleteL Ta90apth 8lnslaetl lnlecllon Valve 12/12/2018 2P-02) zembae) Casing Strings CON,DUCTORlon OD fin) IG QnI Top(nKS) SN OapM (M(BI SO CepM(rvDF-W6'Len (L.. GnLe Tap TK2a4 CONDUCTOR 16 15.05 30.0 120.0 120.0 62.60 WELDED 2pin(rvG)... Casio Gescllpryon OG6n) ON-, TOD (DKa) Sel Geplll (II KB) Set WIIL[n 9._Gnde Top T11na0 SURFACE ]518 6,8] 30.6 3,029.fi 2,380.0 29J0 am' BTCMOa pn) IG(In) Top (hKel SAOepM(N(BI Sat GepN lrvG)... PRM1en(I... G_do To,_N.. Gelnp Oewtlptlon 1'5" PRODUCTIONS.Sx3.5° 5j/2 4.95 2].9 10,139.5 5,739.0 15W L -e0 BTCMOD @e5d1' Tubing ZMngs Tubing 0eec,lptlon String Ma... IG(In) Top(RKG) fief G Pdh(fl..Sel Depth (1VG)(.,. WI(INn) Gntle Top Cannedlon TUBING 3112 2.99 25] 9,534.d 5,456.5 9.30 L-80 EUE-8M Completion Data eoNYYnOR 30,61300 To (NG) Top N[I Nomlwl Top(ME) (KKB( I°I INm ON, GT Ib (end 25.7 25.7 0.00 HANGER FMC HANGER 3.500 NIPPLE;MUA 532.4 532.1 5.21 NIPPLE CAMCO DSNIPPLE NO GO PROFILE 2.875 MIDOT VALVe see 9,471.1 9,-4 9 62221 SLEEVE -C BAI(ER CMU SLIDING SLEEVE 2.813 9,487.1 5,434.4 62.01 NIPPLE CAMGDD NIPPLE 2.750 9,531.7 5,455A 61.48 LOCATOR 6AKER LOCATOR 3.000 9,5320 5,455.8 61.4J SEALASSY BAKER GBH-225EALASSY 3.W0 Other In Hole (Wireline retrievable plugs, valves, pumps, fish, etc.) TeP(rvD) rep Incl cAs uFr. zaze.z Top IRK¢) (M(6) (� Gas Gm FIn mN m(In) 532,4 532.0 5.21 INJECTION 28]5 GLOCKw/A-11NJ VALVE (.9108EAN, OAL=4T) iZ62018 0.910 VALVE Perforations & Slots Shc Dap TOP(nKB) BM (IIKBI TIP I -D) (No) on DI (KKD) Dnketl IDne Dele Nhamm ) Type Conn 6uRFACF'9os3,m9.a- 9,645.0 9,)35.0 5,510.2 5,554.02P -0Z) 4232007 6.0 APERF 2.5'HSD GUNS w2506 PJ Ch9s 10.008.0 10,018.0 5,680.1 5,684.7 T-3, 2P-027 101192002 6.0 (PERF 2.5" HSD, JH qDX 250fi Ch9S, SO deg phase,.a dmn orient cns uFr; s,o4s.6 Frac Summary SNrt DeN PropWnl Dnlell.1161 PmpWnln Fennatlw IN 10232002 SaMSIe,t Date Top DNoll(.K.) t.(pKD) UNNHUNSyalem V01 Clean (bp9 VOI31uny(bM1 1 10/232002 10008.0 10,0180 . 111;etssd Mandrel Inserts sl .n on TO, r VDI NNe Leeh Pan SNe m0ft N Top(nKB) INS) Mad Model ODIN) Sew Tme Type I-) (Pal( Run Dae Conn 1 2,629.2 2,192.) CAMCO KRG-2- 1GASLIFT DW IM 0000 0.0 51152002 9 GP6 LIFT; 9,4318 2 6,046.6 3,801.2 CP,MDD KRG-2- 1 GAS LIFT DMY INT 0.000 0.0 5/152002 9 3 8,156.4 4,807.4 CAMCO KBG-2- 1 GASLIFT MY IM DM 0.0 2262005 9 4 9,421.6 5,403.9 CAMCO KBG-2- 1 GASLIFT 5 -My- INT 0.000 0.0 1011712002 9 SLEI VE 9,4711 Notes: General & Safety Entl Mnmamn 1MN 111222010 NOTE:W WSCHEMATIC w/Alaska SLhemadldS NIPPLE Bg6).f LOC4TOP; 9,5]f T 9FALA&SY; 8,533.0 FPERF: Bb4560,)350� (PERF: 10pH.0.10,DlU0 FPAC: lo:..O .o PHO..1; 8511': ZT.g40.198.5 ., N,I STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to im. Fenn (Olalaska.00vAOGCC.InspectorsGDalaskaoOv' phoebe. brooks(5alaska.0av OPERATOR: ConocOPhillips Alaska Inc FIELD/UNIT/PAD: Kuparuk/KRU/2P Pad DATE: 10/01/19 OPERATOR REP: Van Camp / Hills AOGCC REP: Brian Bixbv chris.vrellace(d>alaska Oov Well 2P-427 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. O= Other (describe in Notes) PTD 2020180 Typelnj W Tubing 840 840 840 840Type O = Other (describe in notes) Test P Packer TVD 5456 BBL Pump 2.8 IA 70 3200 3100 3100 Interval O Test psi 2900 BBL Return 2.8 OA 755 780 777 777 Result P Nates: MITIA per Sundry# 318-054 conversion from GINJ to WAG injection Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer ND BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes: TYPE [NJ Codes TYPE TEST Cates INTERVAL Codes Result Codes W=Water P=Pressure Test 1=Initial Test P=Pass G=Gas O= Other (describe in Notes) 4=Four Year Cycle F=Fail S=slurry V= Required by Variance 1=Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting Form 10426 (Revised 01/2017) MIT KRU 2P-427 10.01-19.xlsx Annular Communication Surveillance Well Name: 2P-427 Start Date: 20 -Jul -2019 Days: 90 End Date: 18 -Oct -2019 4000 Injection Rate Summary Pressure Summary 450 E400 U 350 - 170 3500 .. S 250 - 3000 Y � 200 150 N 2500. V150 __. N c 100 130 LL m a 50 a 2000 - - •i ay N Y. N N `-I f-1 r4 ri en eo c4 m .-1 m m r H ri rl N rl c -I N m tin m co ¢¢ ate. 6 ci a ri n ci a .-1 a¢ ri rl ..� N N ci .-1 Y Y O J 3 J J fI1 1p Oi d d ¢ ¢ 7 ¢ J J ¢ d J J v v ¢ ¢ d ¢ M Ll vl Ll M v vl v N d M v M v M O V t V V U O O O O O N N N N ci a n O M tL Ol N N In tlJ' fy m N 41 N tf1 W 110 y n O M 6 Ol N LIl M' cY rl rl N N N M rl r-1 ri N N N M rl c -I N —DGI -MGI —PWI ®SWI —BLPD a` 1500 - a 90 1000 ._.. ... _ 500 70 Q .. ._ 50 m m m m m m m m m m m m m m m m rn m m m m m m m m m m m m m m Nam tiva m oO aN - ¢ d ¢ ¢ W 0 0 0 0 0 0 N N N N ri CI h O M 6 dl N A W' A M 6 M N LA M' r'' V n O M tO Cl N Vl W rl rl N rl N N N M H rl c -I N N N M rl r-1 rl —WHP —IAP —OAP —WHT 500 Injection Rate Summary 450 E400 U 350 - ° 300 0 S 250 - Y � 200 V150 N c 100 50 •i ay N Y. N N `-I f-1 r4 ri en eo c4 m .-1 m m r H ri rl N rl c -I N m tin m co ¢¢ ate. 6 ci a ri n ci a .-1 a¢ ri rl ..� N N ci .-1 Y Y O J 3 J J fI1 1p Oi d d ¢ ¢ 7 ¢ J J ¢ d J J v v ¢ ¢ d ¢ M Ll vl Ll M v vl v N d M v M v M O V t V V U O O O O O N N N N ci a n O M tL Ol N N In tlJ' fy m N 41 N tf1 W r-1 y n O M 6 Ol N LIl M' cY rl rl N N N M rl r-1 ri N N N M rl c -I N —DGI -MGI —PWI ®SWI —BLPD Annular Communication Surveillance 2P-427 2P-427 2P-427 2P-427 10/4/19 9/25/19 9/24/19 9/21/19 420 155 260 801 185 300 151 227 235 -145 109 574 INNER INNER INNER INNER PWI PWI PWI PWI E RECEIVED ConocoPhillips Alaska FEB 4,2018 AOGCC Marc Lemons Manager, GKA Base Production And Optimization Greater Kuparuk Area ConocoPhillips Alaska, Inc. ATO -1376 PO Box 100360 Anchorage AK 99510-0360 Phone (907) 265-6112 February 16th, 2018 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 West Th Ave. Suite 100 Anchorage, Alaska 99501-3539 Re: Request to allow water injection Meltwater Oil Pool Area Injection Order 21 B, Rule 8 Dear Commissioner French, ConocoPhillips Alaska, Inc. ("CPAP') submits the enclosed information in response to the question posed at the February 81h, 2018 hearing on the Meltwater area injection order. Please contact Vanessa Angel (907) 265-1018 if you have questions or require additional information. Regards, Marc Lemons Manager, GKA Base Production North Slope Operations and Development Q: How much gas volume has been bled from the 2P-431 OA bleed system? A: ConocoPhillips stated in a letter to AOGCC dated 1/26/2016, that between 2/18/2015 and 12/8/2015 30 MMSCF was bled from the outer annulus ("OK) of 2P-431 into production through a continuous OA bleed system. We believe this information remains accurate. After recently reviewing the continuous bleed system data, it is estimated that CPAI has bled an additional 17 MMSCF from the 2P-431 OA between 12/9/2015 and 2/15/2018. 3 TRANSCRIPTOFPUBLIC._—ARING 2/8/2018 DOCKET NO.AIO 17-041 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application of ConocoPhillips Alaska, Inc., for the Revision of Area Injection Order 21B to Allow for the Injection of Beaufort Sea Water and Produced Water from the Kuparuk River Unit for Enhanced Oil Recovery Purposes. t No.: AIO 17-041 BEFORE: Hollis Daniel Cathy PUBLIC HEARING February 8, 2018 Anchorage, Alaska 10:00 o'clock a.m. French T. Seamount Foerster Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC_ —ARING 2/8/2018 DOCKET NO. ATO 17-041 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chair French 03 3 Remarks by Ms. Angel 09 4 Remarks by Ms. Benavente 15 5 Remarks by Mr. Perfetta 22 6 Remarks by Mr. Neely 44 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC- -ARING 2/8/2018 ( DOCKET NO. AIO 17-041 Page 3 1 P R O C E E D I N G S 2 (On record - 10:00 a.m.) 3 CHAIR FRENCH: Let's go ahead and get started. 4 It's February 8, 2018, it's 10:00 o'clock in the 5 morning. We are at 333 West Seventh Avenue in 6 Anchorage. This is the Alaska Oil and Gas Conservation 7 Commission. The bench here consists of Cathy Foerster, 8 Commissioner Cathy Foerster to my right, Dan Seamount, 9 Commissioner Dan Seamount to my left and I'm Hollis 10 French, I'm the Chair of the Commission. 11 We're here today on docket number AIO 17-041, 12 it's regarding the Meltwater pool in the Kuparuk River 13 Unit. And the request is to authorize water injection 14 for enhanced recovery operations. 15 ConocoPhillips Alaska, Incorporated by 16 application dated December 22nd, 2017, requests that 17 the AOGCC revise rule 8 of area injection order 21B to 18 allow for the injection of Beaufort Sea water and 19 produced water from the Kuparuk River Unit for enhanced 20 oil recovery purposes. 21 Computer Matrix will be recording the 22 proceedings, you can get a copy of the transcript from 23 Computer Matrix Reporting. 24 I have a list here of those who have signed in 25 and those who intend to testify. I understand there Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLIC.. BARING 2/8/2018 I DOCKET NO.AI017-041 Page 4 1 may be some people here who did not sign in. If you 2 would please do so, it just helps us keep records of 3 who comes and goes at the hearings, if you haven't 4 signed in please find the sheet that's available and do 5 so. 6 Please, Commissioner Foerster. 7 COMMISSIONER FOERSTER: Jody Colombie has the 8 sign in sheet. 9 CHAIR FRENCH: Oh, yeah, the sign in sheet. If 10 you're looking for it..... 11 COMMISSIONER FOERSTER: Let's -- we'll take a 12 minute and -- let's take a minute and let them do that. 13 CHAIR FRENCH: Okay. Anyone who has not signed 14 in, this is your chance to wave your hand and ask for 15 that sign in sheet. 16 COMMISSIONER FOERSTER: Okay. 17 CHAIR FRENCH: I'm not seeing any takers. Very 18 good. 19 ConocoPhillips of course is going to testify. 20 Any other parties planning to testify? 21 (No comments) 22 CHAIR FRENCH: I don't see any hands there 23 either. 24 During the hearing the Commissioners will ask 25 questions during the testimony, we also may take a Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC .TARING 2/8/2018 DOCKET NO. AlO17-041 Page 5 1 recess to consult with staff to determine whether 2 additional information or clarifying questions are 3 necessary. If a member of the audience has a question 4 that he or she feels should be asked, please submit 5 that question in writing to Jody Colombie, the same 6 person who was just waving the sign in sheet. They 7 will provide the question to the Commissioners, to us, 8 and if we feel that asking the question will assist us 9 in making our determinations we will ask it. 10 For those testifying please keep in mind that 11 you must speak into the microphone so that those in the 12 audience and the court reporter can hear your 13 testimony. Also please remember to reference your 14 slides as you go along so that someone reading the 15 public record can follow along. For example refer to 16 slides by their numbers or by their titles if they're 17 not numbered. 18 In general we have just a few ground rules on 19 what is allowed relative to testimony. First all 20 testimony must be relevant to the purposes of the 21 hearing that I outlined a few minutes ago and to the 22 statutory authority of this agency. Anyone desiring to 23 testify may do so, but if the testimony drifts off 24 subject we will limit that testimony. Testimony may 25 not take the form of cross examination, as I said Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC-'ARING 2/8/2018 DOCKET NO. AIO 17-041 Page 6 1 before the Commissioners will be asking the questions. 2 Finally testimony that is disrespectful or 3 inappropriate will not be allowed. 4 Commissioner Foerster and Seamount, do you have 5 anything to add? 6 COMMISSIONER SEAMOUNT: I have nothing. 7 CHAIR FRENCH: Commissioner Foerster. 8 COMMISSIONER FOERSTER: I was about to say even 9 though I worked for Conoco for a few years there's no 10 one in the room..... 11 COMMISSIONER SEAMOUNT: Turn your mic on, 12 please. 13 COMMISSIONER FOERSTER: Oh, sorry. Sorry, 14 Nathan. 15 CHAIR FRENCH: Oh, it went on and off. There 16 you go. 17 COMMISSIONER FOERSTER: I was about to say that 18 even though I worked for Conoco for years, there's 19 nobody in here from Conoco that worked with me or that 20 I know, but then I realized that I have to disclose to 21 you that, I don't think it will prejudice me, but one 22 of the Conoco employees planning to testify had her 23 religious education impacted by me when she was 13 24 years old. So..... 25 CHAIR FRENCH: We'll just look and see who's Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLIL _ _EARING 2/8/2018 i DOCKET NO. A1O17-041 Page 7 1 blushing the hardest and that'll be probably the last 2 of that inquiry. And thank you, Commissioner Foerster 3 for that. 4 COMMISSIONER SEAMOUNT: That's scary, 5 Commissioner Foerster. 6 CHAIR FRENCH: Interesting background. 7 COMMISSIONER FOERSTER: Well, please say a 8 prayer for her. 9 COMMISSIONER SEAMOUNT: I don't think there's 10 any hope. 11 COMMISSIONER FOERSTER: Maybe not. 12 CHAIR FRENCH: Out of a desire to continue this 13 hearing on the -- in the direction in which it was 14 originally aimed, I will just go from left to right if 15 you would please and introduce yourselves, first name 16 and last name to us. 17 MR. PERFETTA: Patrick Perfetta. 18 CHAIR FRENCH: Patrick. And how do you spell 19 your last name, Patrick? 20 MR. PERFETTA: P -E -R -F -E -T -T -A. 21 CHAIR FRENCH: Patrick Perfetta. And next. 22 MS. ANGEL: Vanessa Angel. 23 CHAIR FRENCH: Thank you, Vanessa. 24 MS. BENAVENTE: Xindi Benavente. 25 CHAIR FRENCH: Xindi. And -- oh, I see, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLk -ARING 2/8/2018 DOCKET NO. AIO17-041 1 Benavente. Thank you. 2 MS. BENAVENTE: Yes. 3 CHAIR FRENCH: And you, sir. 4 MR. NEELY: Thomas Neely, N -E -E -L -Y. 5 CHAIR FRENCH: Mr. Neely. Any reason why we 6 can't swear all witnesses in at the same time? 7 Would you all please raise your right hand. 8 (Oath administered) 9 IN UNISON: I do. 10 CHAIR FRENCH: Excellent. Then I'll just turn 11 the hearing over to you, let you decide amongst 12 yourselves how to proceed and please go ahead. 13 COMMISSIONER FOERSTER: And introduce 14 yourself..... 15 CHAIR FRENCH: Yes. 16 COMMISSIONER FOERSTER: .....as you testify for 17 the good of the court reporter. 18 CHAIR FRENCH: Thank you, Commissioner 19 Foerster. Very important. 20 MS. ANGEL: Thank you. 21 CHAIR FRENCH: Good morning. 22 MS. ANGEL: Good morning. My name is Vanessa 23 Angel and I'm the reservoir engineer for Meltwater 24 field for ConocoPhillips Alaska. 25 COMMISSIONER FOERSTER: Do we want to offer Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBL}k BARING 2/8/2018 DOCKET NO.AIO 17-041 Page 9 1 them the opportunity to be recognized as experts. 2 CHAIR FRENCH: Excellent. Thank you, 3 Commissioner Foerster. 4 Any of you wishing to be recognized as an 5 expert in your respective fields should begin your 6 testimony by saying, yes, I'd like to be an expert in 7 reservoir engineering. And then that will lead into a 8 quick inquiry of your credentials and a quick ruling on 9 that request from the bench. 10 So please go ahead. 11 VANESSA ANGEL 12 previously sworn, called as a witness on behalf of 13 CPAI, testified as follows on: 14 DIRECT EXAMINATION 15 MS. ANGEL: Thank you. I'm here with my 16 colleagues to represent ConocoPhillips as the operator 17 of the Kuparuk River Unit and the Meltwater oil pool. 18 I'll be testifying this morning as a representative of 19 ConocoPhillips. And I would like to be recognized as 20 an expert in reservoir engineering. 21 CHAIR FRENCH: Please tell us a little bit 22 about your background and your education in that field. 23 MS. ANGEL: I graduated with a bachelor of 24 science in chemistry in 2007 from the University of 25 Alaska Anchorage. And in 2011 I received my master's Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIk- !ARING 2/8/2018 i DOCKET NO. AIO17-041 Page 10 1 degree in petroleum engineering from the University of 2 Alaska Fairbanks. I worked as a chemist with Jacobs 3 Engineering from 2008 to 2011 and as a reservoir 4 engineer for ConocoPhillips Alaska from 2011 until 5 today. I have worked the Meltwater field from August, 6 2015 until present. 7 CHAIR FRENCH: Any other questions from the 8 bench about Ms. Angel's qualifications with respect to 9 her desire to be an expert -- recognized as an expert 10 in reservoir engineering? 11 COMMISSIONER FOERSTER: I have no questions and 12 no concerns. 13 CHAIR FRENCH: Commissioner Seamount. 14 COMMISSIONER SEAMOUNT: Same here. 15 CHAIR FRENCH: With that we will recognize you 16 as an expert. Please continue. 17 MS. ANGEL: Thank you. The Meltwater team is 18 with me today to present information and address your 19 question. In addition to myself we have Xindi 20 Benavente, senior facilities development engineer. She 21 will provide an overview of the Meltwater surface 22 facility and operation. Pat Perfetta, staff geologist, 23 he will provide the Meltwater oil pool geology and 24 Thomas Neely, a staff geologist who is also the Alaska 25 representative for the ConocoPhillips subsurface Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLIk- TARING 2/8/2018 ( DOCKET NO. AIO17-041 Page 11 1 containment assurance team. They will present 2 qualifications to be recognized as experts in their 3 respective fields as the presentation proceeds. 4 Also joining us this morning is Eric Castillo, 5 North Slope development manager, Mark Lemon, GKA base 6 production and optimization manager and Liz Jolley, the 7 CPF2 supervisor. 8 Unless you have any questions for me at this 9 time I'll begin the presentation. 10 This is slide two. Today's hearing arises from 11 ConocoPhillips' request to amend area injection order 12 21B. Prior to reviewing the amendment request I would 13 like to give a brief summary of key events that have 14 occurred to date with respect to injection in the 15 Meltwater oil pool since the original area injection 16 order was issued in 2001. 17 In August of 2001 the original area injection 18 order 21 was issued. Elevated OA pressures were noted 19 in April of 2002. Composition sampling of the outer 20 annulus gas confirmed the presence of miscible 21 injectant or MI. An investigation was then initiated 22 to determine the source and migration mechanism for MI, 23 but as 2003 no migration pathway was identified. From 24 2003 to 2011 ConocoPhillips managed the elevated outer 25 annulus pressures and periodically updated AOGCC. In Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net TRANSCRIPTOFPUBLIt- _c.ARING r 2/8/2018 DOCKET NO.AIO 17-041 Page 12 1 2011 a likely migration pathway was identified through 2 linear features that were mounted vertically into the 3 overburden. With this new information the AOGCC was 4 notified and containment initiatives were developed. 5 ConocoPhillips requested amendments to the area 6 injection order in October of 2012 and after hearings 7 the AOGCC issued area injection order 21A. 8 ConocoPhillips again requested amendments to the area 9 injection order in April of 2015 and after a hearing 10 the AOGCC issued the current area injection order 21B. 11 In December, 2017 ConocoPhillips as operator 12 and on behalf of the working interest owners submitted 13 a request to amend area injection order 21B. The 14 amendment arises from analysis that indicates low 15 pressure water flood of the Meltwater oil pool will 16 increase incremental recovery by 1 to 2 percent of the 17 original oil in place or OOIP while reducing operating 18 concerns due to freezing and low flow. It will also 19 allow for developmental opportunities to be pursued. 20 The last OOIP provided to the AOGCC was 60 million 21 barrels in 2012. And this number is still relevant. 22 This is slide three. I would like to now 23 explain the requested amendment to the area injection 24 order. Rule 8 of AIO 21B lists the fluids authorized 25 for injection. Fluids I and J are Beaufort Sea water Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOF PUBLIC BARING 2/8/2018 DOCKET NO. ATO 17-041 Page 13 1 and Kuparuk River Unit or KRU produced water used for 2 surveillance, logging, near wellbore formation 3 displacements and well maintenance. CPAI would like to 4 propose amending rule 8 to remove restrictions on 5 Beaufort Sea water and KRU produced water. The crossed 6 out text indicates text CPAI would like removed from 7 the area injection order. 8 This is slide four. Today's presentation will 9 provide details of the Meltwater oil pool and the 10 benefits of low pressure water injection. The 11 Meltwater team and I will begin this presentation with 12 an overview of the Meltwater field. We will then move 13 into a summary of the point forward benefits of water 14 injection, we will then discuss the injected fluids' 15 compatibility with the reservoir and we will conclude 16 today's presentation with a summary of the containment 17 initiatives and our closing remarks. 18 I will begin with an overview of the Meltwater 19 field. 20 This is slide six. The operator of the 21 Meltwater development is ConocoPhillips Alaska. The 22 surface owner is the State of Alaska and the working 23 interest owners are ConocoPhillips Alaska, BP 24 Exploration, Chevron USA and ExxonMobil Alaska. 25 This is slide seven. This slide shows the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC -TARING 2/8/2018 DOCKET NO. AIO17-041 Page 14 1 location of Meltwater on the North Slope of Alaska. It 2 is the southern most satellite of GKA. The Meltwater 3 pool is highlighted in pink. Meltwater is a light oil, 4 low perm, turbidite reservoir. And the reservoir and 5 oil properties are listed on this slide for reference. 6 The geology of Meltwater will be covered in more detail 7 later. 8 This is slide eight. This slide shows the 9 bottom hole locations and services of wells that have 10 been drilled within the Meltwater field. The blue 11 outline indicates the Meltwater participating area. 12 The green circles indicate wells in production service 13 and the blue triangles indicate those in injection 14 service. And the red stars indicate wells that have 15 been plugged and abandoned. All wells are drilled from 16 a single drillsite, 2P, the location of which is 17 indicated by the brown rectangle in the northwest 18 corner of the participating area. 19 The Meltwater North 2 well was a discovery well 20 drilled in 2000. Delineation wells, Meltwater North 2A 21 and Meltwater North 1, were drilled later that year. 22 The exploration and delineation well bottom hole 23 locations are indicated by the yellow circles. 24 Development drilling began in 2001. Currently 25 there are 11 producers and eight injectors. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC. _BARING 2/8/2018 i DOCKET NO. AlO17-041 Page 151 1 CHAIR FRENCH: Ms. Angel, I have a simple 2 question for you. Is the Meltwater pool above or below 3 the Kuparuk A sands and C sands? 4 MS. ANGEL: Would you like to answer that? 5 Introduce yourself first. 6 MR. PERFETTA: Patrick Perfetta. The Meltwater 7 pool is above stratigraphically..... 8 CHAIR FRENCH: Thank you. 9 MR. PERFETTA: .....compared to the Kuparuk. 10 CHAIR FRENCH: Just a general orientation. 11 Thank you. 12 MR. PERFETTA: Uh-huh. 13 MS. ANGEL: At this point I will hand the 14 presentation to Xindi Benavente to discuss the surface 15 facilities. 16 CHAIR FRENCH: Ms. Benavente, good morning. 17 XINDI BENAVENTE 18 previously sworn, called as a witness on behalf of 19 CPAI, testified as follows on: 20 DIRECT EXAMINATION 21 MS. BENAVENTE: Good morning. My name is Xindi 22 Benavente and I'm the senior facility development 23 engineer for Meltwater. I would like to be recognized 24 as an expert in facility engineering. 25 CHAIR FRENCH: Okay. Tell us about your Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC BARING 2/8/2018 DOCKET NO. AIO 17-041 Page 16 1 qualifications. 2 MS. BENAVENTE: Thank you. I graduated from 3 the University of Tulsa in 2006 with a degree in 4 chemical engineering. I also have a master's in 5 business from the University of Houston in 2012. I 6 have worked for ConocoPhillips in multiple business 7 units in the areas of projects and facilities for 11 8 years and I have spent the last three years working in 9 Alaska and two of which on Meltwater. 10 I will be reviewing the surface facility of 11 Meltwater oil pool. 12 CHAIR FRENCH: Okay. And just one second. Any 13 questions for Ms. Benavente about her qualifications as 14 a facility engineer? 15 COMMISSIONER FOERSTER: I have no questions and 16 no reservations. 17 COMMISSIONER SEAMOUNT: Ms. Benavente, is your 18 master's in chemical engineering also? 19 MS. BENAVENTE: No, my master's is in business. 20 COMMISSIONER SEAMOUNT: In business. I have no 21 other questions or objections. 22 CHAIR FRENCH: We will recognize you as an 23 expert in facility engineering. Please go ahead. 24 MS. BENAVENTE: Thank you. This is slide 10. 25 The figure in this slide shows the production and Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net TRANSCRIPT OFPUBLA c,ARING 2/8/2018 DOCKET NO. AIO17-041 Page 17 1 injection system connecting central processing facility 2 2 or CPF2 located at the upper right-hand corner to the 3 drillsites on the west end pipeline system which 4 includes drillsite 2M, drillsite 2S, drillsite 2L, 5 drillsite 2N and drillsite 2P. In general lean gas or 6 MI is delivered to the drillsites by the eight inch gas 7 injection pipeline in red. Water is delivered to the 8 drillsites from CPF2 by the 12 inch water injection 9 pipeline in blue. However the drillsite 2N to 10 drillsite 2P portion of the water injection pipeline 11 was proactively removed from service due to internal 12 corrosion in 2009. Therefore there is currently no 13 functional water injection pipeline to drillsite P2. 14 Meltwater is a single gravel pad, drillsite 2P, 15 that can be accessed by gravel road. Drillsite 2P is 16 approximately 10.3 miles from the nearest drillsite 2 17 Nancy. And approximately 26 miles from CPF2. Water 18 was used for injection and artificial lift until 2009. 19 At that point Meltwater was converted to MI injection 20 and gas lift. In July, 2014, the importation of 21 Prudhoe Bay natural gas liquids or NGL into the Kuparuk 22 River Unit were discontinued and the Meltwater field 23 was then converted to lean gas injection and lean gas 24 lift only service. 25 Authorized fluids for injection do not Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLI( .BARING 2/8/2018 DOCKET NO. AIO17-041 Page 18 1 currently include water because previously there was no 2 plan to replace or repair the water injection line 3 because of the capital requirement and the superior 4 performance of gas injection. However the field is now 5 near the end of its life due to high GOR and 6 ConocoPhillips believes water injection will keep the 7 field online for an additional five to 10 years. 8 COMMISSIONER FOERSTER: I have a couple 9 questions. 10 CHAIR FRENCH: Commissioner Foerster. 11 COMMISSIONER FOERSTER: First how long has 12 Meltwater had GOR issues? I guess that's more of a 13 question for Ms. Angel. 14 MS. ANGEL: I'll have a plot of that on a later 15 slide if you'd like to see it. 16 COMMISSIONER FOERSTER: Okay. I'll hold on 17 until then. And my second question is the other pads, 18 2N, 2L, 2S, 2M, are those are all Kuparuk producing 19 pads or are any of those..... 20 MS. ANGEL: 2L and 2N are Tarn. 21 COMMISSIONER FOERSTER: Are Tarn. Which is 22 similar to Meltwater in geologic time. Okay. 23 CHAIR FRENCH: And just a final on your -- on 24 your diagram here, it looks as if water injection is 25 happening at 2N, 2L, 2S, 2M, but abandoned in place to Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIt- BARING 2/8/2018 DOCKET NO. AIO17-041 Page 191 1 2P? 2 MS. ANGEL: That is correct. 3 CHAIR FRENCH: Thank you. Good diagram. 4 MS. ANGEL: Thank you. 5 MS. BENAVENTE: This is slide 11. Shown on a 6 sketch in the bottom right corner the concept to 7 restore water injection is to convert the existing 8 eight inch gas injection line to water injection 9 service. Produced water will be sourced by a new 10 pipeline jumper at drillsite 2 Nancy connecting the 11 existing 12 inch water injection pipeline to the eight 12 inch gas injection pipeline. Injection water will be 13 delivered on pad through a second pipeline jumper at 14 drillsite 2P, connecting the gas injection pipeline to 15 the on pad water injection system. Pig launcher and 16 receiver will be installed at drillsite 2N and 17 drillsite 2P for annual maintenance and inline 18 inspection ILI pigging and corrosion monitoring 19 purposes. Post project water will begin -- water will 20 become the only injection and lift fluid for the 21 reservoir, wells will be converted from gas lift to jet 22 pump. 23 Any questions for me? 24 CHAIR FRENCH: Just one. What will become of 25 the abandoned in place, the old water injection line, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIt- BARING 2/8/2018 ( DOCKET NO. AI017-041 Page 20 1 the 2P, what happens to that? 2 MS. BENAVENTE: It was abandoned in place. 3 CHAIR FRENCH: It's just going to sit quietly 4 waiting for something? 5 MS. BENAVENTE: Well, we follow the 6 ConocoPhillips procedure to properly abandon in place 7 and deinventory the line and wind it. 8 CHAIR FRENCH: You got a separate -- okay. 9 MS. BENAVENTE: Yes. 10 CHAIR FRENCH: But for the time being -- for 11 the foreseeable future, two, three, four years, it just 12 sits there waiting..... 13 MS. BENAVENTE: Yes. 14 CHAIR FRENCH: .....you never know. Okay. 15 Understand. 16 COMMISSIONER SEAMOUNT: Ms. Benavente, are 17 these pipelines buried? 18 MS. BENAVENTE: No. 19 COMMISSIONER SEAMOUNT: Okay. When you pig a 20 pipeline I -- I assume that the pigs are very accurate 21 equipment to determine where the location of the pig 22 is? 23 MS. BENAVENTE: Yes. We have pig zigs (ph), 24 that's banded -- fixed externally to the pipeline so 25 that we know where the pig is traveling. Whenever it Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIL- BARING 2/8/2018 DOCKET NO. AIO17-041 Page 211 1 is traveling through a spot we know. 2 COMMISSIONER SEAMOUNT: Plus or minus inches or 3 centimeters or what? 4 MS. BENAVENTE: I think at this point you -- we 5 actually know it when -- like because it's magnetic and 6 so we know when the pig is traveling through. And then 7 because the pipeline's so long we can -- we can monitor 8 the pig's speed, we know approximately where the pig is 9 during that 10.3 miles. But at the location of the pig 10 zig we know pretty accurately that -- when the pig is 11 traveling through a pig zig. 12 COMMISSIONER SEAMOUNT: Are you concerned about 13 freezing? 14 MS. BENAVENTE: We have a slide actually 15 later..... 16 COMMISSIONER SEAMOUNT: Okay. 17 MS. BENAVENTE: .....answering the freezing 18 question. 19 CHAIR FRENCH: Please proceed. 20 MS. BENAVENTE: Okay. Unless there's any other 21 question for me I will hand the presentation to Patrick 22 Perfetta for an overview of Meltwater geology. 23 CHAIR FRENCH: Mr. Perfetta. 24 PATRICK PERFETTA 25 previously sworn, called as a witness on behalf of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLI� -ARING 2/8/2018 ' DOCKET NO. AIO17-041 Page 22 1 CPAI, testified as follows on: 2 DIRECT EXAMINATION 3 MR. PERFETTA: This is slide 12. My name is 4 Patrick Perfetta, I would like to be recognized as an 5 expert in geology. 6 CHAIR FRENCH: Tell us about your 7 qualifications. 8 MR. PERFETTA: Well, my background on education 9 and industry experience is I earned a bachelor of 10 science degree in geology from Indiana University of 11 Pennsylvania in 1996, followed by a master of science 12 in geology from the University of Missouri in 1998. I 13 worked for ConocoPhillips and its heritage companies 14 for 20 years in various roles ranging from exploration 15 and production to technical oversight. I have been 16 responsible for geologic interpretations of Meltwater 17 field on several occasions dating back to 2009, most 18 recently since 2016. 19 I'll be presenting an overview of Meltwater 20 field geology unless there are any questions right now. 21 CHAIR FRENCH: I'll first turn to Commissioner 22 Seamount to see if he has any questions or objections. 23 COMMISSIONER SEAMOUNT: No questions or 24 objections. 25 CHAIR FRENCH: Commissioner Foerster. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUB LIC BARING 2/8/2018 DOCKET NO. AIO17-041 Page 23 1 COMMISSIONER FOERSTER: I just have one 2 question. which campus of the University of Missouri 3 did you go? 4 MR. PERFETTA: It was in Columbia. 5 COMMISSIONER FOERSTER: Columbia. Okay. I 6 have no reservations. 7 CHAIR FRENCH: You're an expert in geology. 8 Please proceed. 9 MR. PERFETTA: Thank you. This is slide 13. 10 The image on the left of the slide is a map showing the 11 location of Meltwater field in relation to the nearby 12 Kuparuk River and Tarn fields. Meltwater is located 13 approximately eight miles to the southwest of Kuparuk 14 field and the stratigraphic column at the right which 15 is representative of the central North Slope, depicts 16 Meltwater field which is located within the Brooking 17 sequence and is associated with the CB formation. The 18 producing reservoir at Meltwater field is locally known 19 as the Bermuda sandstone. It is interpreted that the 20 Bermuda is a deep water turbidite deposit. 21 This is slide 14. This slide is a well logged 22 structural cross section which traverses from northwest 23 to southeast across the Meltwater field. As depicted 24 on the map to the lower left by cross section line A to 25 A prime, the cross section depicts the reservoir Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLI� 'ARING 2/8/2018 / DOCKET NO. AIO17-041 Page 24 1 characteristics of the Bermuda reservoir interval which 2 is highlighted in yellow shading. Four wells are 3 identified across the top, 2P 434, 417, 422A and 422. 4 The text boxes at the bottom of the first three wells 5 show average reservoir properties of each well from 6 petrophysical interpretation. 7 The 2P 422 well to the right is interpreted to 8 have possibly intersected the field oil/water contact. 9 Though the gross Bermuda reservoir interval is 10 generally continuous across Meltwater field, the 11 internal stratigraphy is complex as individual sand 12 units are difficult to correlate between wells. This 13 discontinuous nature is illustrated by changes in 14 various petrophysical curves between wells, 15 specifically the gamma ray which is the brown curve in 16 track one, the green pay flags in track two, and the 17 permeability curves, the pink curve in track two. The 18 2P 417 well exhibits the best overall reservoir quality 19 particularly in the upper portion of the Bermuda as 20 illustrated by the permeability curve. The 422A well 21 on the other hand exhibits better reservoir quality at 22 the base of the gross interval. 23 Additional insight into the discontinuous or 24 compartmentalized nature of the Bermuda will be 25 discussed next. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLIL .SARING 2/8/2018 ( DOCKET NO. AlO17-041 Page 25 1 This is slide 15. This slide illustrates the 2 interpreted stratigraphic complexity within the gross 3 Bermuda reservoir interval in the Meltwater field. The 4 map is an interpretation of the various reservoir 5 bodies present in the field represented by the polygon 6 outlines. The pay sands are contained within deep 7 water channel levy to low (indiscernible) deposits and 8 are characterized by poor lateral connectivity between 9 individual reservoir bodies. The deviated well 10 trajectories are depicted as gray lines and overprint 11 the interpreted reservoir bodies. Penetration points 12 from the top Bermuda reservoirs are represented by red 13 Xs. The map was generated through the integration of 14 all available subsurface data including core, well 15 logs, 3D seismic and production performance data. 16 An analysis of 4D seismic was completed in 17 Meltwater field in 2012. This analysis identified 18 linear features that align with the azimuth of maximum 19 principal stress. The linear features are depicted in 20 this illustration as dashed black lines trending 21 north/northwest to south/southeast. 22 This is slide 16. This slide depicts an 23 interpreted geoseismic section of the gross Bermuda 24 interval. The traverse of the cross section is shown 25 by the red line from B to B prime on the map at the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIL .?ARING 2/8/2018 DOCKET NO. AIO 17-041 Page 26 1 left. The reservoir bodies have been interpreted from 2 the 3D seismic character and are consistent with the 3 geologic and production data from the field. The 4 geoseismic section illustrates the individual reservoir 5 bodies within the gross Bermuda interval which is 6 depicted by the blue dashed lines. Production data 7 from the field indicates poor connectivity between 8 individual lobes. 9 Unless there are any questions from the 10 Commission at this time I'll hand the presentation back 11 to Vanessa Angel and she'll be providing a..... 12 CHAIR FRENCH: Commissioner Seamount. 13 COMMISSIONER SEAMOUNT: Yes. Mr. Perfetta, is 14 these seismic anomalies, are they going to be discussed 15 in more detail? 16 MR. PERFETTA: No, that's all we have to..... 17 COMMISSIONER SEAMOUNT: Could you..... 18 MR. PERFETTA: .....on those from this 19 presentation. 20 COMMISSIONER SEAMOUNT: .....characterize what 21 these anomalies represent? 22 MR. PERFETTA: The 4D are time shifts in the 23 seismic related to a combination of pressure, gas 24 saturation and fractures that are -- that extend above 25 the reservoir as well. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBUL ?ARMG 2/8/2018 DOCKET NO. AIO17-041 Page 27 1 COMMISSIONER SEAMOUNT: I seem to recall about 2 five years ago we had a hearing and we saw some seismic 3 lines and we saw these anomalies and they extended to a 4 point where it looked like the seismic data got garbled 5 so we didn't know how high up they went. And I think 6 at the time the discussion centered around these are 7 anomalies where MI may be -- may have escaped. Have 8 you -- have you changed your interpretation at all 9 since then? 10 MR. PERFETTA: We have not changed our 11 interpretation since then on the generation of those -- 12 those liniments. 13 COMMISSIONER SEAMOUNT: But that is where you 14 think some of that MI went to; is that correct? 15 MR. PERFETTA: Yeah, we think that a small 16 amount of gas could be contributing to those artifacts. 17 COMMISSIONER SEAMOUNT: Is there a possibility 18 it got -- it went to the surface? 19 MR. PERFETTA: No, there's no evidence of any 20 of those liniments extending to the surface. There's 21 no surface artifacts associated with them. 22 COMMISSIONER SEAMOUNT: Have you done any 23 surface gas studies, soil sample studies, anything like 24 that to see if any of that gas may have gone that high? 25 MR. PERFETTA: We have not done any surface Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net TRANSCRIPTOFPUBLIk_ 2ARING 2/8/2018 DOCKET NO. AI017-041 Page 28 1 sampling, just looking at satellite images and..... 2 COMMISSIONER SEAMOUNT: Satellite images, it 3 would -- what would they tell you? 4 MR. PERFETTA: The high resolution gives you an 5 indication of any liniments that could be at the 6 surface. 7 COMMISSIONER SEAMOUNT: Okay. But it won't 8 give you an indication of whether there's gas at the 9 surface. Have you ever considered doing any surveys? 10 MR. PERFETTA: Not that I'm aware of. 11 COMMISSIONER SEAMOUNT: Yeah, I know that your 12 staff changes quite a bit in that field. So I think it 13 would be interesting to know if there was any anomaly 14 concerning escaped gas at the surface. But you don't 15 think there's much chance of that, right? 16 MR. PERFETTA: No, I don't think that that's -- 17 that's the case. 18 COMMISSIONER SEAMOUNT: Okay. I have no other 19 questions. 20 CHAIR FRENCH: Commissioner Foerster. 21 COMMISSIONER FOERSTER: So you mentioned 4D. 22 Could you tell me what the years were that you've taken 23 the different seismic surveys? 24 MR. PERFETTA: Yes. So the original survey was 25 in 1999 and then the follow-up survey was in 2008. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIL BARING 2/8/2018 DOCKET NO. AIO17-041 Page 29 1 COMMISSIONER FOERSTER: Okay. But do you have 2 any plans to do anything else? 3 MR. PERFETTA: We do not have any current plans 4 of shooting another seismic survey. 5 COMMISSIONER FOERSTER: Okay. Okay. Thank 6 you. 7 COMMISSIONER SEAMOUNT: Oh, one other question. 8 I can't remember what depth did you estimate that the 9 seismic data went to pot, got garbled, was that -- was 10 that one second or..... 11 MR. PERFETTA: I really..... 12 COMMISSIONER SEAMOUNT: .....was it higher? 13 MR. PERFETTA: It was slightly higher than 14 that. We mapped the liniments up to the C37 interval 15 and we have good data quality slight above that 16 interval. 17 COMMISSIONER SEAMOUNT: Okay. 18 COMMISSIONER FOERSTER: What depth is that? 19 MR. PERFETTA: The C37 occurs in -- let me 20 check my exact note. Yeah, so the C37's at roughly 21 3,200 feet subsea TVD. 22 COMMISSIONER FOERSTER: So above 3,200 your 23 seismic data is challenged? 24 MR. PERFETTA: Yeah. We do have data above 25 that that's of decent quality. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLI� .c,ARING 2/8/2018 1 DOCKET NO. AIO17-041 Page 30 1 COMMISSIONER FOERSTER: I'm going to let that 2 lie unless you want..... 3 CHAIR FRENCH: Well, just for the public 4 member, if your data begins to be less reliable around 5 3,200, remind me what the TVD of the pool is? 6 MR. PERFETTA: Right. The Bermuda's 7 approximately 2,200 feet deeper than that so it's 8 around 5,300 feet on average, yeah. 9 CHAIR FRENCH: 53, 54. Okay. 10 COMMISSIONER FOERSTER: I think the issue is 11 not whether they had good resolution to understand the 12 pool, it's whether..... 13 CHAIR FRENCH: Above there. 14 COMMISSIONER FOERSTER: .....they had 15 resolution of the geology to understand where the 16 fluids were migrating. 17 CHAIR FRENCH: Right. And I just want to make 18 sort of a gross -- I mean, and gross is the right word, 19 you know, sort of understanding of, you know, where the 20 pool is, where the data begins to degrade and I 21 think..... 22 COMMISSIONER FOERSTER: Gotcha. 23 CHAIR FRENCH: .....think I have that. 24 Excellent, Mr. Perfetta. Thank you. Who's 25 next. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLI. 2ARING 2/8/2018 r DOCKET NO. Al017-041 Page 31 1 MR. PERFETTA: Vanessa Angel. 2 CHAIR FRENCH: Excellent. 3 MS. ANGEL: Thank you. This is Vanessa Angel 4 again and I will be reviewing the benefits of water 5 injection point forward in Meltwater oil pool. 6 This is slide 18. The injection history of 7 Meltwater is shown in the upper plot on this slide. MI 8 injection is shown in a red solid line, water injection 9 is shown with a blue solid line and lean gas injection 10 is shown with a green solid line. The lower plot shows 11 gas/oil ratio of Meltwater oil pool in a dotted red 12 line. 13 Commissioner Foerster, does this answer your 14 question? 15 COMMISSIONER FOERSTER: So when did -- kind of. 16 So at what point did the GOR become an issue? 17 MS. ANGEL: You can see in mid 2014 to the end 18 of 2014, we started to see spikes in GOR. We had 19 increased our injection rate by quite a bit that year 20 so we pulled back on injection rate, but GOR continued 21 to rise. 22 COMMISSIONER FOERSTER: So it was until it -- 23 so the 6 million standard cubic feet per barrel wasn't 24 a problem to you? 25 MS. ANGEL: And it's not so much that that GOR Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLI. 3ARING 2/8/2018 DOCKET NO. AIO 17-041 Page 32 1 is a problem, I guess it's the trend going forward is 2 going to be a problem because with continued gas 3 injection the GOR will continue to climb. 4 COMMISSIONER FOERSTER: Okay. So my question 5 was at what point did you become concerned about the 6 GOR as being a facility limiter or having an impact on 7 your recovery, would it be at the 6 million or was when 8 it started spiking? 9 MS. ANGEL: Well, I know in 2015 we were 10 looking forward to the future and knowing that this 11 would be a problem. Does that answer your question? 12 13 COMMISSIONER FOERSTER: I think a better answer 14 would be I wasn't here in 2011 so I don't know. Is 15 that a fair statement? 16 MS. ANGEL: That's fair. 17 COMMISSIONER FOERSTER: Okay. 18 MS. ANGEL: 2015 was when I started. I just 19 remembered..... 20 COMMISSIONER FOERSTER: Okay. 21 MS. ANGEL: .....that that was a concern at 22 that time. 23 COMMISSIONER FOERSTER: Okay. Thank you. 24 MS. ANGEL: In 2012 the reservoir engineer 25 stated MI injection should remain the voided Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLk .TARING 2/8/2018 DOCKET NO. AIO 17-041 Page 33 1 replacement ratio and enhanced oil recovery mechanism 2 for the Meltwater field until MI is no longer available 3 from the Kuparuk River Unit. Following the MI flood a 4 lean gas chase may be performed to recover any trapped 5 NGLs in the Meltwater reservoir and also water 6 injection may be used. As you can see from the upper 7 plot MI injection was used in Meltwater until 2014 when 8 it was no longer available. Then the field was flooded 9 with lean gas to recover NGLs and manage voidage. This 10 flood mechanism was effective, however the gas/oil 11 ratio of the field has been increasing. With continued 12 lean gas injection it is expected to continue 13 increasing. 14 COMMISSIONER FOERSTER: And the lean -- the MI 15 was no longer available because Prudhoe quit sending it 16 to you? 17 MS. ANGEL: Yes. We switched the pipeline to 18 import gas instead of NGLs. 19 This is slide 19. The upper plot again shows 20 the Meltwater injection history. The lower plot shows 21 Meltwater oil production rate in blue solid lane and 22 gas production rate in a blue dotted line. The CPF2 23 facility is limited by how much gas it can process. 24 Wells flowing to CPF2 are therefore sorted by the 25 gas/oil ratio and wells with the highest gas/oil ratio Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLII 2ARING 2/8/2018 DOCKET NO. AIO 17-041 Page 34 1 are shut in. If a number of Meltwater wells are shut 2 in and the flow from the Meltwater drillsite drops too 3 low, the 24 inch production line is at risk from 4 freezing. The modeled minimum flow rate to prevent 5 freezing concerns is approximately 300 barrels of oil 6 per day, however it would be necessary to maintain a 7 much higher fluid rate so that operations would not be 8 at risk if one or two wells were to be shut in 9 unexpectedly. In addition high gas production rates 10 for Meltwater back out oil from other drillsites on the 11 shared production line. A shut in test was performed 12 at Meltwater drillsite this summer and it was estimated 13 that the 13 million scuffs per day of gas production 14 from Meltwater acts out approximately 900 barrels per 15 day from other areas of CPF2. Water injection would 16 allow oil production from Meltwater to continue while 17 greatly reducing gas production. 18 Next I will talk about the options available if 19 water injection is not approved. 20 This is slide 20. We currently inject lean gas 21 into Meltwater. Lean gas is problematic because it is 22 leading to high GORs, however lean gas is also not 23 going to be available for injection starting in August 24 of 2018. In August of 2018 the line that supplies gas 25 injection to the west end drillsites, drillsite 2M, 2S, Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email sahile@gci.net TRANSCRIPT OFPUBLI. BARING 2/8/2018 ( DOCKET NO. AIO17-041 Page 35 1 2N, 2L and 2P will be switched from lean gas injection 2 to MI injection. The purpose of this change is to 3 target amongst other opportunities the new drillsite 2S 4 development. MI is a valuable and limited resource. 5 Meltwater does not compete with the other targets 6 available for MI injection. For this reason CPAI would 7 prefer not to use MI at Meltwater. 8 CHAIR FRENCH: Just one or two again general 9 kind of gross questions. Where will the MI come from 10 in 2018? 11 MS. ANGEL: We will be switching the line over 12 from gas imports to NGL imports. So it'll come from 13 Prudhoe Bay. 14 CHAIR FRENCH: Okay. That's my question. 15 MS. ANGEL: Another option is that the 16 Meltwater field could be shut in either temporarily or 17 permanently. Shutting in the drillsite permanently is 18 the lowest oil recovery option. Lastly the field could 19 produce with no injection. I will discuss that option 20 further on the next slide. 21 COMMISSIONER FOERSTER: Shutting in permanently 22 is the lowest recovery, how about shutting in 23 temporary? 24 MS. ANGEL: That would just put things on hold 25 and it would depend on what you decided to do later. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLI 2ARING 2/8/2018 I DOCKET NO. AIO17-041 Page 36 1 COMMISSIONER FOERSTER: So that wouldn't impact 2 ultimate recovery. Okay. 3 CHAIR FRENCH: And one final question. I'm 4 sure it's been discussed, but why not resize your 5 production header at least at that far end of the field 6 from 2P to 2N? 7 MS. ANGEL: The question is if you would resize 8 the production line from 24 inch to be smaller? 9 CHAIR FRENCH: You would have less concern -- 10 you have less concern about freezing. 11 MS. ANGEL: I believe the cost is a problem. 12 Xindi, would you like to comment on that. 13 MS. BENAVENTE: Yes, that 24 inch pipeline is 14 actually 10.3 miles going from 2P to 2 Nancy. And..... 15 CHAIR FRENCH: Lot of pipe..... 16 MS. BENAVENTE: It is. 17 CHAIR FRENCH: .....for a little bit of oil. 18 MS. BENAVENTE: For the production from 19 Meltwater it would not support it, the pipeline 20 replacement or reduction economically. 21 CHAIR FRENCH: I understand. Thank you. 22 MS. ANGEL: This is slide 21. To compare 23 development scenarios a simulation model was built. 24 This model represents a part of the field. The part of 25 the field included in this model is noted by the maroon Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLI CARING 2/8/2018 I DOCKET NO. AIO17-041 Page 371 1 box over the Meltwater map in the upper right-hand 2 corner of this slide. The model results are 3 unconstrained meaning the field limitations are not 4 applied. And the results of this plot are not scaled 5 up to whole field. The water injection scenario is 6 shown in blue and the depletion scenario is shown in 7 pink. The solid lines, pink and blue, are oil 8 production rates and the dotted lines, pink and blue, 9 are average bottom hole pressures. This shows that 10 with no injection support the reservoir pressure and 11 oil rate will drop rapidly. Quickly dropping 12 production rates would mean that a production line 13 would be in danger of freezing. In the depletion 14 scenario it is likely that the production line would be 15 proactively shut in within one to two years of stopping 16 injection. 17 When the results from the simulation model are 18 used and applied to a realistic development scenario 19 with an integrated view of CPF2 it is estimated that 20 water injection will bring an incremental 1 to 2 21 percent recovery above the next best option. 22 This is slide 22. Water flood also enables 23 possible future development drilling through CTD. As 24 stated in the 2015 hearing follow-up questions, CPAI 25 believes 2 to 7 million barrels of incremental oil Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email sahile@gci.net TRANSCRIPTOFPUBLIi .3ARING 2/8/2018 � DOCKET NO.AIO 17-041 Page 381 1 could be obtained through development drilling by 2 connecting injection and production within the 3 disconnected lobes. If the flooding mechanism is 4 changed to water this will extend the field life and 5 allow time for these development opportunities to be 6 pursued. 7 This is slide 23. This slide explains the 8 concept that water injection will be able to alleviate 9 low flow and freezing concerns. The distance between 10 drillsite 2P and drillsite 2N is 10.3 miles. As 11 production drops from Meltwater oil pool there is an 12 ongoing freezing concern in the 24 inch PO line shown 13 here in green due to the low production volume from 14 drillsite 2P. With water injection the water available 15 for injection can be split into two streams. One 16 stream will flood the Meltwater reservoir, the other 17 stream will remain in the surface facilities and it 18 will be continuously recycled from the injection system 19 into the production system to keep the production line 20 warm. This continuous loop of injection water will 21 keep the production line above freezing even as 22 Meltwater production rates decline. 23 Commissioner Seamount, does this answer your 24 question on freezing concerns? 25 COMMISSIONER SEAMOUNT: Yes, it does. Thank Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLk EARING 2/8/2018 r DOCKET NO. A1O17-041 Page 39 1 you. 2 CHAIR FRENCH: And just to drive the point 3 home, you're just going to take warm seawater and put 4 it in your production header? 5 MS. ANGEL: It will likely be produced water. 6 CHAIR FRENCH: Produced water. Fair enough. 7 Right. Right. 8 MS. ANGEL: And we'll split the stream, some of 9 it will flood the reservoir. 10 CHAIR FRENCH: Some of it goes downhole..... 11 MS. ANGEL: Right. 12 CHAIR FRENCH: .....but some of it just goes 13 straight back in your header to keep stuff -- fluids 14 moving in that pipe? 15 MS. ANGEL: That's correct. 16 CHAIR FRENCH: Got it. Thank you. 17 MS. ANGEL: It was requested from the AOGCC 18 that we cover evidence that the proposed fluids are 19 compatible with the reservoir. I will discuss that 20 now. 21 This is slide 25. I will give examples of both 22 the flooding history and core flood studies with the 23 proposed fluids and Meltwater rock. To review, the 24 proposed fluids are KRU produced water and Beaufort Sea 25 water. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBd) .TARING 2/8/2018 DOCKET NO.AIO 17-041 Page 40 1 First flooding history. The field was flooded 2 with KRU produced water from 2003 to 2009 and no water 3 compatibility impacts were noted. The field has not 4 been fully flooded with Beaufort Sea water, but 5 seawater was trucked into Meltwater in 2015 for a water 6 flow injection logging campaign and no adverse affects 7 were noted. 8 Next core flood studies. A Meltwater fluid 9 sensitivity study was completed in March of 2001. This 10 study utilized core samples from the Meltwater North 1 11 and Meltwater North 2 wells. The flood waters in the 12 study included KRU produced water and a blend of 75 13 percent KRU produced water and 25 percent Beaufort Sea 14 water. The investigation concluded that there were no 15 adverse reactions to the 75 percent KRU produced water, 16 25 percent Beaufort Sea water blend. An example of the 17 core flood results is shown in the figure on this 18 slide. Permeability is measured on the Y axis. In 19 pink, 100 percent KRU produced water is being used and 20 in blue the injection water is switched to 75 percent 21 KRU produced water and 25 percent seawater. There is 22 no appreciable difference in the permeability between 23 the two flood waters. 24 COMMISSIONER FOERSTER: Before you change 25 slides, is the 75/25 representative of what you expect Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLk .:TARING 2/8/2018 DOCKET NO. A1O17-041 Page 411 1 to be injecting? 2 MS. ANGEL: No, I'm anticipating we will use 3 100 percent produced water. We no longer mix our 4 waters so there's maybe a 5 percent chance or less that 5 we would use 100 percent seawater. 6 COMMISSIONER FOERSTER: Okay. So you're not -- 7 it won't blend, it'll be either or? 8 MS. ANGEL: Yes. 9 COMMISSIONER FOERSTER: Okay. Thank you. 10 MS. ANGEL: I will now discuss how 11 ConocoPhillips ensures continued containment at 12 Meltwater. 13 This is slide 27. This slide lists the current 14 containment initiatives and how they will change with 15 water injection. I will start by describing the 16 containment monitoring initiatives that are required by 17 the area injection order and follow-up with the 18 additional CPAI containment monitoring initiatives. 19 20 There are no changes proposed to the 21 containment initiatives required by the area injection 22 order. The first initiative is an injection pressure 23 limit of 3,400 psi at the sand face. This injection 24 pressure limit has been in place since 2012 and average 25 OA pressures have fallen since that time. The second Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net f TRANSCRIPTOFPUBLk -EARING 2/8/2018 ( DOCKET NO. AlO17-041 Page 42 1 initiative is continuous OA pressure monitoring and 2 advisory alarms set to alert operators of changing 3 pressures. This allows us to respond immediately if OA 4 pressures increase to near 1,000 psi. 5 COMMISSIONER FOERSTER: So is it safe to assume 6 that you have had any of those alarms go off since 7 you've maintained the 3,400 psi or is that -- has it? 8 MS. ANGEL: No, we periodically bleed wells if 9 they get near 1,000 psi and that still occurs. 10 COMMISSIONER FOERSTER: Okay. 11 MS. ANGEL: The third initiative is continued 12 formation pressure monitoring at injectors and 13 producers. Shut in bottom hole pressures in injectors 14 and producers allow us to infer the level of injection 15 support being provided by the flood. Monitoring water 16 injectivity in the injectors will give us an indication 17 if the water is continuing to be injected in zone. 18 Now I will discuss the additional CPAI 19 containment initiatives. The first initiative is 20 quarterly fluid levels of the OA in each well. This 21 allows CPAI to monitor the fluid levels over time and 22 estimate the pressure at the casing shoe in the outer 23 annulus of each well. This initiative will stay the 24 same. 25 CHAIR FRENCH: Okay. So just so I'm clear Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC- -ARING 2/8/2018 / DOCKET NO. AIO 17-041 Page 43 1 that's happening now, you're shooting quarterly fluid 2 levels? 3 MS. ANGEL: That's correct. 4 CHAIR FRENCH: Okay. Thank you. And so why is 5 it an additional initiative, do you see what I mean? 6 MS. ANGEL: I was just listing what we do right 7 now and if we're planning on changing it. 8 COMMISSIONER FOERSTER: This is required by us 9 and this is something they do on their own. 10 CHAIR FRENCH: On their own. But it's not 11 additional to the request you're making today, this is 12 something you intend -- you have been doing and you 13 intend to continue doing? 14 MS. ANGEL: Yes. 15 CHAIR FRENCH: Okay. Okay. Thank you. 16 MS. ANGEL: The second initiative is biannual 17 bleeds and OA gas analysis. I will discuss this in two 18 parts. The first part is biannual bleeds -- is 19 biannual outer annulus bleeds. OA pressures have 20 dropped so low in many wells that biannual bleeds are 21 no longer necessary to stay below a thousand psi. The 22 plan going forward is to bleed the outer annuli on an 23 as needed basis to stay below 1,000 psi in our well 24 operating guidelines and AIO rule 21, AIO 21B, rule 3. 25 CPAI believes that gathering long term OA pressure data Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC- —ARING 2/8/2018 DOCKET NO. AIO 17-041 Page 44 1 without bleeds will be more helpful to identify 2 anomalous OA pressure behavior. 3 The second part is gas sampling. Gas samples 4 have been taken since 2012 and a review of gas samples 5 to date was included in the application for this AIO 6 amendment request. Gas samples have not indicated a 7 loss of containment to date and in addition it will not 8 be helpful to indicate the presence of water. 9 Therefore the plan forward is to discontinue gas 10 sampling once water injection starts. 11 Are there any questions on these? 12 CHAIR FRENCH: I don't see any. 13 MS. ANGEL: Okay. At this point I will hand 14 the presentation to Thomas Neely for an overview of the 15 ConocoPhillips corporate subsurface containment 16 program. 17 CHAIR FRENCH: Mr. Neely. Good morning. 18 THOMAS NEELY 19 previously sworn, called as a witness on behalf of 20 CPAI, testified as follows on: 21 DIRECT EXAMINATION 22 MR. NEELY: Morning. My name is Thomas Neely. 23 I would like to be recognized as an expert in geology. 24 CHAIR FRENCH: Please tell us about your 25 qualifications. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC —ARING 2/8/2018 r DOCKET NO. A1O17-041 Page 45 1 MR. NEELY: I earned a bachelor of science 2 degree in geological sciences from the University of 3 California Santa Barbara in 2003, followed by a master 4 of science degree in geology from Colorado State 5 University in 2006. I have worked as a geologist for 6 ConocoPhillips for 12 years and have worked as a 7 geologist in Alaska since 2015. 8 I'm a member of the ConocoPhillips Alaska 9 subsurface containment assurance team and I'll be 10 presenting today on the ConocoPhillips containment 11 assurance program. 12 CHAIR FRENCH: Commissioner Seamount, any 13 questions? 14 COMMISSIONER SEAMOUNT: University of 15 California Santa Barbara's a good school. I have no 16 questions or objections. 17 COMMISSIONER FOERSTER: Nor do I. 18 CHAIR FRENCH: You're an expert in geology, Mr. 19 Neely, please continue. 20 MR. NEELY: Thank you. ConocoPhillips has a 21 corporate requirement that business units assess and 22 mitigate risks associated with loss of injected or 23 produced fluids out of their intended reservoir 24 interval or associated wellbores. This requirement 25 applies to all ConocoPhillips operated assets. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLI(._ ARING 2/8/2018 DOCKET NO.AIO17-041 Page 46 1 Part of the requirement involves multi 2 functional risk assessments of the subsurface system of 3 our operated assets including geological features, 4 wellbore integrity and operating conditions. These 5 assessments involve geoscientists, reservoir engineers, 6 production engineers, drilling engineers and operation 7 staff. Additionally subsurface containment assurance 8 training is required for ConocoPhillips staff in 9 geoscience, reservoir engineering, operations, wells 10 and asset management roles. 11 Subsurface containment assessments have been 12 conducted on Meltwater on a regular basis since 2013. 13 As a result of the containment initiatives undertaken 14 by the asset since 2012 Meltwater is in compliance with 15 the ConocoPhillips corporate requirements for 16 subsurface containment assurance. 17 Unless there are any questions from the 18 Commission I'll hand the presentation back to Vanessa 19 Angel. 20 COMMISSIONER FOERSTER: I have questions. 21 CHAIR FRENCH: Commissioner Foerster. 22 COMMISSIONER FOERSTER: I have a few questions 23 for you. Do you want to start with the specific or the 24 esoteric? Okay. We'll go specific. Do you feel that 25 when you had the loss of containment problems that they Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIC _.�ARING 2/8/2018 DOCKET NO. A1O17-041 Page 47 1 were related to injection of water, not having the 2 3,400 pressure limit or a combination of the two? 3 MR. NEELY: So the question is whether or not 4 the..... 5 COMMISSIONER FOERSTER: The earlier. 6 MR. NEELY: .....earlier containment issues 7 were related to just water, just gas or a combination? 8 COMMISSIONER FOERSTER: No, just -- just the 9 comb -- okay. When we changed what we were doing we 10 went from water and gas to just gas and we put a 11 pressure limit on it. Do we feel that eliminating the 12 water had any impact on improving the containment or 13 was all of the containment improvement achieved by 14 limiting the pressure? Does that make it more clear 15 what I'm asking? 16 MR. NEELY: It does, yes. And I'll defer some 17 of the specifics of that question to Vanessa, but I'll 18 start just by saying that we feel that it was the 19 containment initiative around reducing (indiscernible) 20 injection pressure..... 21 COMMISSIONER FOERSTER: Okay. 22 MR. NEELY: .....that was primarily responsible 23 for our assessment that we were able to achieve 24 subsurface containment. COMMISSIONER FOERSTER: 25 Okay. So when you qualify it by saying primarily Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC. _ _BARING 2/8/2018 r DOCKET NO. AlO17-041 Page 48 1 pressure that leaves the door open that water was part 2 of the problem? 3 MR. NEELY: I'll defer that portion of the 4 question to Vanessa..... 5 COMMISSIONER FOERSTER: All right. 6 MR. NEELY: .....if it's okay. 7 MS. ANGEL: Yes, I would agree that lowering 8 the pressure is the primary reason that we're able to 9 have containment now. 10 COMMISSIONER FOERSTER: Okay. So I'll say what 11 I said before. Primarily as a qualifier it leaves the 12 door open to the possibility that water was part of the 13 problem. Is -- are you concerned at all that water was 14 part of the problem? 15 MS. ANGEL: I believe that water at high 16 pressure was part of the problem, but I'm not concerned 17 about water at low pressure. 18 COMMISSIONER FOERSTER: So you think it was the 19 combination of the two together. All right. That 20 takes care of that question. Now my second question is 21 back to Mr. Neely. Since your job is containment 22 assurance and I'm assuming you weren't here when the 23 initial problems were. Okay. It probably isn't going 24 to make Conoco any money to try to understand what 25 happened to that missing 250 million cubic feet of gas Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC. -ARING 2/8/2018 � DOCKET NO. AIO17-041 Page 491 1 or where it went, but do you have any theories? 2 MR. NEELY: I think I'll defer that question to 3 the geologist, Pat Perfetta. 4 MR. PERFETTA: I guess the 250 million cubic 5 feet are you referring to? 6 COMMISSIONER FOERSTER: Well, our records 7 indicate that you lost 300 million cubic feet of what 8 you injected and that you were able to recover 50 of it 9 which is 300 minus 50 leaves 250 that you can't account 10 for. 11 MR. PERFETTA: I -- a small percentage of that 12 could be entrained in the -- in the overburden..... 13 COMMISSIONER FOERSTER: Okay. 14 MR. PERFETTA: .....as we've stated from a -- 15 in the modeling work that we've done, you know, for the 16 time shifts and overburden, some small portion of that 17 is related to gas, yeah, but it's not quantifiable just 18 how much that is. 19 COMMISSIONER FOERSTER: Okay. So since that's 20 a small portion, do you have any theories of where the 21 significant portion is? 22 MR. PERFETTA: It could still be in the 23 reservoir. 24 COMMISSIONER FOERSTER: What's the likelihood 25 that it's in the reservoir since you know you had a Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLIC.--.ARING 2/8/2018 DOCKET NO. AIO17-041 Page 50 1 problem with it leaving the reservoir? 2 MR. PERFETTA: Yeah, I guess I would defer that 3 to Vanessa. 4 MS. ANGEL: That 250, get my MM -- my units 5 right, MMSCF of gas is estimated to exist somewhere 6 above the reservoir. 7 COMMISSIONER FOERSTER: So is -- are there any 8 plans to try to find it? 9 MS. ANGEL: We currently bleed continuously out 10 of well 2P 431 and that gas goes into production. We 11 also do the regular bleeds if the OAs are getting near 12 a thousand. But as the outer annuluses of many of the 13 wells start to fall below -- well below 1,000, that 14 will be the end of what we capture of that gas. 15 COMMISSIONER FOERSTER: Okay. That'll be it 16 for now. 17 COMMISSIONER SEAMOUNT: The subsurface 18 containment assessments you say have been conducted 19 since 2013, I mean, is that like official containment 20 assessments because I assume that you're doing 21 assessments ever since the problem was noted in what, 22 2002? 23 MR. NEELY: That's right. The 2013 date refers 24 to the formal assessments that are a part of this 25 ConocoPhillips subsurface containment assurance requirement. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC. .TARING 2/8/2018 � DOCKET NO. AIO 17-041 Page 51 1 COMMISSIONER SEAMOUNT: Is that company wide? 2 MR. NEELY: Yes. 3 COMMISSIONER SEAMOUNT: Okay. Thank you. 4 COMMISSIONER FOERSTER: I do have one more 5 question. Have you had this -- and maybe this is 6 another one for Vanessa or Mr. Perfetta, is -- first is 7 Tarn in a comparable reservoir to Meltwater? 8 MR. PERFETTA: So the comparison between Tarn 9 and Meltwater, they are both turbidite reservoirs, but 10 Tarn is slightly different geologically, it's a little 11 bit more laterally continuous and not as 12 compartmentalized as Meltwater is. 13 COMMISSIONER FOERSTER: And stratigraphically 14 is it -- are they comparable depths? 15 MR. PERFETTA: They're essentially 16 equivalent..... 17 COMMISSIONER FOERSTER: Okay. 18 MR. PERFETTA: .....in depth. 19 COMMISSIONER FOERSTER: That's what I was 20 looking for. And have you had any problems with 21 containment in Tarn because I know you've been 22 injecting at Tarn? 23 MR. PERFETTA: No, we have not -- we don't have 24 any evidence of anything leaving the Tarn oil pool. 25 COMMISSIONER FOERSTER: Okay. Thank you. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OF PUBLIC .ARING 2/8/2018 ( DOCKET NO. AIO17-041 Page 52 1 MS. ANGEL: This is Vanessa Angel again on 2 slide 29. In conclusion CPAI is requesting an 3 amendment to AIO 21B to improve the recovery of 4 Meltwater oil pool by allowing Kuparuk produced water 5 and/or Beaufort Sea water to be used as an injection 6 fluid in Meltwater oil pool under rule 8. By returning 7 the field to water injection it is predicted that the 8 field life will be extended by five to 10 years, an 9 additional 1 to 2 percent of OIP will be recovered and 10 it will be possible to unlock the development potential 11 of 2 to 7 million barrels of oil. 12 Thank you. 13 CHAIR FRENCH: Thank you. I am going to at 14 this point say we'll probably take about a 13 or 14 15 minute recess until 10 minutes after 11:00 while we 16 confer with out staff and we'll come back and see if we 17 have any further questions for you. So just stand by, 18 you can stretch your legs, use the bathroom as you 19 wish, we'll be back at about 10 after 11:00. 20 (Off record) 21 (On record) 22 CHAIR FRENCH: We'll go back on the record and 23 Commissioner Foerster has just a couple of follow-up 24 questions. 25 COMMISSIONER FOERSTER: How much gas are you Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOF PUBLIC .TARING 2/8/2018 DOCKET NO. Al017-041 Page 53 1 getting out of 2B 431, daily rate, monthly rate, 2 whatever you want to do it in? 3 MS. ANGEL: We have a pressure system in the OA 4 so when it was originally installed it had to build up 5 to 350 psi and then it would bleed off. We were having 6 trouble with that pressure setting so we increased it 7 to like eight or 900 psi and we have not bled gas since 8 that point. 9 COMMISSIONER FOERSTER: And when did you -- 10 okay. So a different question. Have you got a 11 guesstimate or an estimate or an accurate determination 12 of how much you got out of that well before it stopped 13 total? 14 MS. ANGEL: I would have to get back to you. 15 COMMISSIONER FOERSTER: Is that something that 16 you can get back to us? 17 MS. ANGEL: Absolutely. 18 COMMISSIONER FOERSTER: And we'll -- we have 19 the opportunity to leave the record open for a number 20 of days until..... 21 CHAIR FRENCH: And we'll do that. 22 COMMISSIONER FOERSTER: And we'll do that. 23 CHAIR FRENCH: What do you think is a 24 reasonable amount of time for you to get that answer? 25 MS. ANGEL: I would like to request 30 days. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste, 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPTOFPUBLII tr_.cARING 2/8/2018 DOCKET NO. AIO17-041 Page 54 1 CHAIR FRENCH: Thirty days. 2 COMMISSIONER FOERSTER: Okay. 3 CHAIR FRENCH: We'll keep the record open for 4 30 days. 5 COMMISSIONER FOERSTER: Unless my next question 6 is one that they want to..... 7 CHAIR FRENCH: Might be an even harder 8 question. Let's see. 9 COMMISSIONER FOERSTER: No, it won't. You say 10 that you're going to do quarterly fluid levels, is 11 there any point in time that you would anticipate that 12 quarterly fluid levels would not be beneficial, is this 13 something that -- you know, you're going to do 14 quarterly fluid levels until the next set of people 15 come in here and don't like fluid levels or is this 16 something that you see as continuing on? 17 MS. ANGEL: I'm actually unsure of the value of 18 the fluid levels, but I'm also unsure if it's smart at 19 this time to stop. I just want the data now and so I 20 want to continue to take them for the foreseeable 21 future. If another engineer comes in they can make a 22 different decision, but for this point in time I'd like 23 to continue gathering them especially as we're doing a 24 change to the reservoir injection, any additional data 25 that we can gather I think is valuable. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net f TRANSCRIPT OFPUBLIC..,6ARING 2/8/2018 ( DOCKET NO. AIO17-041 Page 55 1 COMMISSIONER FOERSTER: Okay. Thank you. 2 Those were my two questions. 3 CHAIR FRENCH: Commissioner Seamount, anything 4 based on those questions and answers that causes you to 5 want to ask anything? 6 COMMISSIONER SEAMOUNT: No, I'd just like to 7 say it's a very complete and organized organization -- 8 organized presentation and I appreciate that. 9 CHAIR FRENCH: Commissioner Foerster, any 10 closing thoughts? 11 COMMISSIONER FOERSTER: I'll keep them to 12 myself. 13 CHAIR FRENCH: I will do the same. I do want 14 to ask you, Ms. Benavente, a question about Tulsa 15 barbecue spots. We'll take that off the record. And I 16 also want to say hello to the CPF2 supervisor. Who's 17 that person, if you could raise your hand. I'll say 18 hello to you after the meeting. 19 With that we are adjourned. Thank you. 20 (Hearing adjourned 11:17 a.m.) 21 (END OF REQUESTED PORTION) 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net TRANSCRIPT OFPUBLIC. _dARING 2/8/2018 ( DOCKET NO. AIO17-041 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Page 56 C E R T I F I C A T E UNITED STATES OF AMERICA ) )ss STATE OF ALASKA ) I, Salena A. Hile, Notary Public in and for the State of Alaska, residing in Anchorage in said state, do hereby certify that the foregoing matter in Docket No.: AIO 17-041 was transcribed to the best of our ability; IN WITNESS WHEREOF I have hereunto set my hand and affixed my seal this 12th day of February 2018. Salena A. Hile Notary Public, State of Alaska My Commission Expires: 09/16/2018 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net 1'e'e � A� // STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket No. AIO-17-041 ConocoPhillips Alaska, Inc. February 8, 2018 at 10:00 am NAME AFFILIATION Testify (yes or no) -jOJil 0016)i1)F31e f)0C9CC- C � vvv l n� At C� CC �av��e�Sc� Arne( C���cGpbl��t��; `I2S IHOMa5 ��6�i �a�ra ari�rP4 Yes ILL&l' les 014rInA (!�afner No Mr.,K 5�.,1�„�� Pl ll'a� &o Az?A+,� C4(u)S CvAf0C,0ffayrs &k> 41txTro Lt- r Coti0CoFt'iI(,-�S No AWoaew wbWaz-y COV%6(b i Ow'12s No To-,, 6-allz No (-4,/ f / P6 /2� L I'Z' JO C.OLI C -0p 14Jc X .A r- )C-C-S1G LA It P'JG 2 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: AIO-17-041 Meltwater Oil Pool, Kuparuk River Unit Authorize Water Injection for Enhanced Recovery Operations ConocoPhillips Alaska, Inc. (CPAI), by application date December 22, 2017, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 8 of Area Injection Order 21B to allow for the injection of Beaufort Sea water and produced water from the Kuparuk River Unit for enhanced oil recovery purposes. The AOGCC has scheduled a public hearing on the application for February 8, 2018, at 10:00 a.m. at 333 West 7`" Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7h Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the February 8, 2018 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than February 1, 2018. Hollis S. French Chair, Commissioner Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: AIO-17-041 Meltwater Oil Pool, Kuparuk River Unit Authorize Water Injection for Enhanced Recovery Operations ConocoPhillips Alaska, Inc. (CPAI), by application date December 22, 2017, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 8 of Area Injection Order 21B to allow for the injection of Beaufort Sea water and produced water from the Kuparuk River Unit for enhanced oil recovery purposes. The AOGCC has scheduled a public hearing on the application for February 8, 2018, at 10:00 a.m. at 333 West 7s' Avenue, Anchorage, Alaska 99501. In addition, written comments regarding this application may be submitted to the AOGCC, at 333 West 7s' Avenue, Anchorage, Alaska 99501. Comments must be received no later than the conclusion of the February 8, 2018 hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC's Special Assistant, Jody Colombie, at (907) 793-1221, no later than February 1, 2018. //signature on file// Hollis S. French Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO, CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATTACHED COPY OF ADVERTISMENT. ADVERTISING ORDER NUMBER AO-I�-�12 U FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 12/29/2017 AGENCY PHONE: (907) 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: I LEGAL DISPLAY CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE Public Hearing AIO 17-041 Initials of who prepared AO: Alaska Non -Taxable 92-600185 :SIIBhI :O iti> rirvQ:;:ceeraiEoxitpitiayit%:y :: ::PUBLIC.ATIbN ADvERTYSmE1SCT0 Department of Administration Division of AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae I of I Total of All Pa cS S REF Type Number Amount Date Comments 1 PVN ADN89311 2 AD AO-18-012 3 4 FIN AMOUNT SY Act. Template PGM LGR Object FY DIST LIQ 1 18 A14100 3046 18 2 3 4 5 rchas t 'tie: Purchasing Authority's Signature Telephone Number .O # and receiving agency name must appear on all invoices and documents relating to this purchase. T state is registered for tax free transactiorm under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for f DISTRJBUTION.: '. :- Division Fbcal/Orsgi":AQ .Copies:: Publisher (faxed); Division Eii cal Be III; Form: 02-901 Revised: 12/29/2017 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, December 29, 2017 10:00 AM To: DOA AOGCC Prudhoe Bay, Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Erickson, Tamara K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator, Alan Bailey; Alex Demarban; Alicia Showalter; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Cody Gauer; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Danielle Mercurio; Darci Horner; Dave Harbour, David Boelens; David Duffy; David House; David McCaleb; David McCraine; ddonkel@cfl.rr.com; Diemer, Kenneth J (DNR); DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Elwood Brehmer; Evan Osborne; Evans, John R (LDZX); Brown, Garrett A (DNR); George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff,, Hurst, Rona D (DNR); Hyun, James J (DNR); Jacki Rose; Jason Brune; Jdarlington oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jill Simek; Jim Shine; Jim Watt; Jim White; Young, Jim P (DNR); Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Larsen, John M (DOR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Kyla Choquette; Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Michael Bill; Michael Calkins; Michael Moora; Michael Quick; Michael Schoetz; Mike Morgan; MJ Loveland; mkm7200; Motteram, Luke A, Mueller, Marta R (DNR); Nathaniel Herz; knelson@petroleumnews.com; Nichole Saunders; Nick Ostrovsky; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Renan Yanish; Richard Cool; Robert Brelsford; Robert Warthen; Sara Leverette; Scott Griffith; Shahla Farzan; Shannon Donnelly; Sharon Yarawsky; Skutca, Joseph E (DNR); Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Tanisha Gleason; Ted Kramer; Teresa Imm; Tim Jones; Tim Mayers; Todd Durkee; Tom Maloney; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Well Integrity; Well Integrity; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Andy Bond; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Corey Munk; Don Shaw; Eppie Hogan; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Keith Lopez, Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Melonnie Amundson; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Rachel Davis; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); William Van Dyke Subject: Public Hearing Notice Attachments: AIO-17-041 Public Hearing Notice Meltwater Oil Pool water injection.pdf Please see attached. Re: Docket Number: AIO-17-041 Meltwater Oil Pool, Kuparuk River Unit Authorize Water Injection for Enhanced Recovery Operations ConocoPhillips Alaska, Inc. (CPAI), by application date December 22, 2017, requests the Alaska Oil and Gas Conservation Commission (AOGCC) revise Rule 8 of Area Injection Order 21B to allow for the injection of Beaufort Sea water and produced water from the Kuparuk River Unit for enhanced oil recovery purposes. Jody J. CoCombie AOGCC SyeciaCAssistant ACaska OiCandGas Conservation Commission 333 'West 71F Avenue Anchorage, ACaska 99501 Office: (907) 793-1221 Fax. (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC(, State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or lodv. colombie@alaska.aov. Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 C'� Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 270227 #1414769 JAN 0 5 2018 $154.38 AFFIDAVIT OF PUBLICATION' STATE OF ALASKA THIRD JUDICIAL DISTRICT Joleesa Stepetin being first duly sworn on oath deposes and says that she is a representative of the Alaska Dispatch News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on December 31, 2017 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate ch ged private i iiduals. , Signed Subscribed and sworn to (before me this 3 day of JA)�— 20 / p Notary Publ' ' and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION EXPO2 S aP ( �I Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: A10-1 7-041 Meltwater Oil Pool, Kuparuk River Unit Authorize Water Injection for Enhanced Recovery Operations ConocoPhillips Alaska, Inc. (CPA0,by application date [ 2017, requests the Alaska Oil and Gas Conservation (AOGCC) revise Rule 8 of Area Injection Order 21B to i Injection of Beaufort Sea water and produced water from River Unit for enhanced oil recovery purposes. The AOGCC has scheduled a public hearing on the ap February 8, 2018, at 10:00 a.m. at 333 West 7th Avenw Alaska 49501. In addition. written rnmmpntc .,din. «him —.1—; If, because of a disability, special at comment or attend the hearincom Jody Colombia, at (907) 793-1221, no //Si nature on file// Hollis S. French Chair, Commissioner Published: December 31, 2017 for Notary Publlc BHITNEY L. THOMPSON State of Alaska My Commission Expires Feb 23, 2019 c H ConocoPhillips Alaska December 22nd. 2017 Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 West Th Ave. Suite 100 Anchorage, Alaska 99501-3539 Re: Request to allow water injection Meltwater Oil Pool Area Injection Order 21 B, Rule 8 Dear Commissioner French, RECEIVED DEC 2 2 2017 AOGCC Marc Lemons Manager, GKA Base Production And Optimization Greater Kuparuk Area ConocoPhillips Alaska, Inc. ATO -1376 PO Box 100360 Anchorage AK 99510-0360 Phone (907) 265-6112 ConocoPhillips Alaska, Inc. ("CPAP'), as operator of Kuparuk River Unit ("KRU") and on behalf of Working Interest Owners, requests that the Alaska Oil and Gas Conservation Commission ("Commission") amend Area Injection Order ("AIO") 21 B, Rule 8 Authorized Fluids for Injection for Meltwater Oil Pool ("Meltwater") to allow injection for enhanced oil recovery. Water injection in the Meltwater Oil Pool stopped in October 2009, because of water supply line corrosion. Since then, only gas has been injected in the pool: miscible injectant to 2014, and then lean gas to date. In AIO 21 B, dated October 8, 2015, the Commission approved Beaufort seawater and KRU produced water for injection specifically for surveillance, logging, near wellbore formation displacements, and well maintenance. Now, CPAI seeks approval to inject both types of water without being limited to the specific purposes. Data supporting this request are included in the attached application. In brief, CPAI seeks approval for water injection because it would increase ultimate recovery, mitigate low -flow and freezing concerns, and support continued development. Enclosed are two printed originals of the application Please contact Vanessa Angel (907) 265-1018 if you have questions or require additional information Regards, Marc Lemons Manager, GKA Base Production North Slope Operations and Development ConocoPhillips APPLICATION FOR AMENDMENT TO MELTWATER OIL POOL AREA INJECTION ORDER 21 B December 22, 2017 Contents 1. Historical Review of Area Injection Order 21.........................................................................................2 2. Proposed Change..................................................................................................................................2 3. Facility and Injection Background..........................................................................................................3 4. Benefits of Water Injection.....................................................................................................................3 a) Water vs. Lean Gas...........................................................................................................................3 b) Water vs. Miscible Gas Injection.......................................................................................................4 5. Maintaining Reservoir Containment.......................................................................................................5 a) Reservoir Pressure............................................................................................................................5 b) Outer Annulus Pressure....................................................................................................................6 c) Outer Annulus Samples.....................................................................................................................7 6. Conclusion............................................................................................................................................10 Page 1 of 10 Fluids authorized for injection are: I . Beaufort Sea water; and j. KRU produced water. 3. FACILITY AND INJECTION BACKGROUND There is currently one operable injection line to drill site 2P, the only drill site for the Meltwater Oil Pool. This line is a gas injection line and it provides injection support and lift gas to the drillsite. The water injection line was decommissioned in 2009. Due to the low permeability of the rock and positive response to MI, it was previously determined that water injection was not beneficial for the reservoir at that time. In the 2012 hearing the reservoir engineer stated: "Therefore MI injection should remain the void replacement and enhanced oil recovery mechanism for the Meltwater Field until MI is no longer available from the Kuparuk River Unit. Following the MI flood a lean gas chase may be performed to recovery any trapped NGLs in the Meltwater reservoir and also water injection may be used." MI was available to the Kuparuk River Unit until 2014. From 2014 until the present time, a lean gas chase was performed at Meltwater. Now, CPAI proposes to inject water as an enhanced oil recovery fluid, for the reasons described in Section 4, below. The lift mechanism would be switched from lift gas to jet pump. 4. BENEFITS OF WATER INJECTION With only one functional injection pipeline to Meltwater, only one fluid can be injected at a time. CPA[ proposes to reduce restrictions on water injection so that the field can be flooded below sandface injection limit of 3400 psi, which will increase oil recovery compared to not injecting water. Estimates below are based on the original oil in place ("OOIP") estimate quoted in the 2012 hearing, 60 million barrels ("MMBBLS" ). The anticipated benefits of low pressure waterflood: - Increases OOIP ultimate recovery 1%-2%; 4 - Extends field life. If water cannot be injected, the field would likely go into depletion or be shut in as it has reached MI maturity and received a lean gas chase. The injection line servicing Meltwater and other Greater Kuparuk Area ("GKA") drill sites will soon be switched back to MI to pursue newly drilled targets, but Meltwater is not a target for MI; and - Allows for a potential 2-7 MMBBLS of targets to be pursued for development drilling (see 2015 hearing follow up questions). Water injection has the added benefit of preventing low flow and freezing concerns in the 24" production line. With water injection, water can be recycled directly from the injection line to the production line. This continuous loop of injection water will keep the production line from freezing even as reservoir production rates decline. A sector model of Meltwater was built for determining which flood mechanism would be most beneficial going forward. The simulation results of water injection are compared to lean gas injection and MI injection. a) Water vs. Lean Gas The modeling work indicates that water injection maintains reservoir pressure better than lean gas injection (Figure 1). Water injection also suppresses GOR while lean gas injection significantly increases it (Figure 2). Water injection allows for a higher overall resource recovery (Figure 1). Page 3 of 10 made up of 2,880 BPD of NGLs. If MI was the only injection fluid available for long term use, it is likely that CPAI would elect to either let the field go on primary depletion or shut in the wells until another recovery mechanism proved economic. u 2019 2020 2021 2022 2023 2024 2025 3026 2027 2028 2029 a a Figure 3: Results from the sector model of OPR and API gravity for WI (blue) and MI (red). The MI injection lasts for 3 years, 2019 — 2022, and is then followed by lean gas injection. 5. MAINTAINING RESERVOIR CONTAINMENT CPAI monitors containment at Meltwater by the following actions: - Maintaining the sandface pressure at or below 3,400 psi; - Tracking daily OA pressures and setting preventative alarms; and Sampling gas, measuring fluid levels, and regularly bleeding the outer annulus ("OX) of all wells. a) Reservoir Pressure The reservoir pressure has dropped at Meltwater since injection pressure was lowered in 2012 (Figure 4). Lowering injection pressure below the fracture pressure of the reservoir (-3400 psi) and below the fracture pressure of the overburden (-3800 psi), helps ensure continued containment. Page 5 of 10 c) Outer Annulus Samples OA gas samples are taken biannually. The wells shown below in Figure 6 indicate a decrease in natural gas liquid ("NGL") content with time. This trend is consistent with previous gas sample data shared with the Commission in the 2015 application for amendment to A1021 A. Mole %n. Swee Tme 10 9 8 7 6 5 4 a •• 2" • see • 0 • • • Marker by: (Pw Nu Color by: xu. .. • 2P-406 • 21`411 SA • 2154417 2Pd19 • 2Pd20 2P422A 2P424A 2P-436 • 2P-447 • 2P-449 Shape by: 1.�, - • ®al values e 0 r Sae by: Figure 6: Decreasing NGL content in OA gas samples over time. Decreasing NGL content in OA gas samples over time. Since 2015, some wells exhibit increasing NGL content in OA gas samples (Figure 7). This trend is explained through pressure, volume, and temperature ('PVT') analysis and is not an indicator of breach of containment. 1 Propane Mole %vs. SWV* Tow Marker by: 10 Color by: 6 2P-432 2P-434 7 •2P-451 Shape by: 6 Nw, 5 - •AII values > • • • Size by: z f; • 2 i • 0 • Figure 7: Increasing NGL content in OA gas samples over time. The three wells with the highest increasing NGL content, also have very low OA pressures (Figure 8). Page 7 of 10 2 �© CS tG � 1441 Figure 10: sample compositions from 2P -448A at 951 psi and 78 psi, both on 12/10/2017. In summary, by monitoring OA gas composition, bleeds, and reservoir and OA pressure CPAI has taken methodical steps to determine there have been no new signs of out of zone migration. We believe containment has been maintained since 2012. Page 9 of 10 ConocoPhillips Meltwater Area Injection Order 21B Amendment Hearing ConocoPhillips Alaska Meltwater Team Meltwater Area Injection Order (AIO) Chronology W August 2001: Original NO 21 Issued W January 2002: Injection Operations begin W April 2002: Increase in OA pressures W 2003 - 2011: Studied and monitored OA pressures W Spring 2012: Identified migration of fluid out of zone with 4D seismic W October 2012: CPAI requested Amendment to NO 21 W May 2013: Amended AIO 21A Issued W April 2015: NO 21A Request for Amendment Submitted W October 2015: NO 21B approved W April 2016: Interim Progress Report Submitted W April 2017: Interim Progress Report Submitted W December 2017: NO 21B Request for Amendment Submitted Activity post 2015 hearing 2 "'is j!I 11 Conamphillips Summary of Requested Amendments to A1O 21B w Rule 8 of A10 21B currently provides in relevant part: w Fluids authorized for injection are: M W i. Beaufort Sea water ,u�-fo;�rve„ne. ,—e=ar wed e fGr-rn-da-&pla- A- i m j. KRU produced water Presentation Outline w Meltwater Field Overview ■ Surface Facilities ■ Geoscience w Benefits of Water Injection ■ Production and Injection History ■ Future Injection Options ■ Water Injection vs. Depletion ■ Development Drilling Benefits ■ Operational Benefits of Water Injection w Injected Fluids Compatibility w Meltwater Containment w Closing Remarks Meltwater Field Overview Meltwater Operations Operator and Surface Owners within One Quarter Mile of Injection Operations m Operator: ConocoPhillips Alaska, Inc. m Surface Owner: State of Alaska m Working Interest Owners • ConocoPhillips Alaska, Inc. (CPAI) BP Exploration (Alaska)Inc. • Chevron U.S.A. Inc. • ExxonMobil Alaska Production, Inc. 6 I1511HS ConocoPhillips Meltwater Overview Oil Properties w API Gravity: 35° W^. w Viscosity: 0.73 cp @ Pbpt & 135 F VNI rALAS. - o Initial reservoir pressure: 2400 psia (at-5400'sstvd) .wwBubble point pressure: 2081 psia InitialGOR: 650SCF/STB Reservoir Properties r °Depositional environment: Deepwater, slope - channel complex N A W Reservoir: Lithic, very fine-grained sandstone 0 5 10 15 20 AtiW W Average Gross: 180' M Peak Production: 12,000 BOPD w Average porosity: 17% (18 - 22% range) M Current Production: 1,000 BOPD w Average perm: 10 and (5-40md range) OOIP: 60 MMSTB M Average SW: 50% Recovered: 19.7 MMBOE (YE 2017) 7 Confidential under AS 38.05.035(a)(9) Conom`Phillips Meltwater Field Wells Meltwater 2P Pad Location 2P-443 2P-034 • ♦ OMWN 2A 2P-417 2P-420 • ♦ 2P-406 • 2P-451 • OMWN 2 2P -415A 2P-032 • 2P-048+ 2P448A ♦ 2P -022A + 2P-415 • 2P-447 • 2P-441 +2P-422 2P449 2P438 2P-429 +2P-424 OMWN 1 2P-427 ♦2P-419 •2P-431 ♦ 2P -424A LEGEND 2.400 1,200 0 2.400 Feet • Producer ♦ Injector N + Plug & Abandon t Meltwater El Participating Area w Discovery Well: ■ Meltwater North 2 (2000) m Delineation Wells: ■ Meltwater North 2A • Meltwater North 1 w Meltwater Field ■ 11 Producers • 8Injectors • 4 Abandoned Bore Holes 8 ????33 t t ConocoPhillips Meltwater Field Overview - Surface Facilities - 10013??ill ConocoPhillips Meltwater Operations Meltwater Facilities 8" Miscible Injectant/Lean Gas Injection Line 12" Water Injection Line (SI) 24" Production Flowline Gravel Road and Pad 4 Bridges 1 Drill Site Overhead Powerline 2P _ Water Injection (WI) Pipeline Current 111111 2M CPF2 „e 24_'110 AIPL— — _ — — —— 2S /OP0 r 8" GI 16, r 12" WI r r \ J 2L "4 -Corners' Intersection QI G 0 a N I 2N 0D I OR -_- — — — — — Pipeline "Abandoned In Place" (AIP) Meltwater 13 Produced Oil (PO) Pipeline Gas Injection (GI) Pipeline 2P _ Water Injection (WI) Pipeline Current 111111 2P GI to WI Conversion Project M Purpose • Convert DS2P from gas injection to water injection M Scope • Install 8" jumper between GI and WI pipeline at 2N • Install 8" WI jumper from GI pipeline to 2P pigging module • Install pig launcher at DS2N and pig receiver at DS2P M Benefits • Reduce GOR for West End pipeline serving 2P, 2N, 2L, 2S, and 2M • Resolve flow concerns for 24" Produced oil line V1 2S- - 9 2N G a °0 a Meltwater I N l� Current Pn I CPF2 24" PO AI PL__I_____ I I 10_WI(AIP)__I "4 -Corners" Intersection 2N O a a 00 a N ( 3 Meltwater 2P 1 Proposed ConocoPhilliP s - .e•a..e: a: � Meltwater Field Overview - Geology - 12 '•..i.; i ConocoPhillips Meltwater Field i ! 1 PoIM J unn otJKF rcw.Mrc SaW�.m Mtlwaxrc anrc �ot�F\e\d _ 1N Meltwater Participating Area 4 Miles Stratigraphic Column Modified from Garrity, 2005 Meltwater Field i' e e?e Con,,Xhillips ............. . 13 Meltwater Field Structural Cross -Section P -422A 2P-434 2P-417 2P-422 , Gross 3.1 t T3 t 7F Bermuda r1 i Reservoir net pay 50' T2 * _ m Po av porosity 20.7% tl zz av perm 7.9 and Po =' Y - r ,tPo Sw 48% Po 1 11 X �tEGEH�°m1wa1f x rwaeuN�ao� L mrt.W reuer net pay 85' av porosity 20.7 av perm 7.3 and Sw 48% net pay 48' av porosity 19.60 / av perm 4.0 and Sw 57% IH .... �a N' SE .Por GR SSTVD/MD RES Neutron / RHOB Bermuda Stratigraphic Complex w Bermuda reservoir is interpreted to be compartmentalized by channel -levee & lobate deposits 0 0 FOCI Meltwater Field Geoseismic Section Gross Bermuda Reservoir B C HT1 `41 2P -422A 2 16 ?'•iiiii' Conomphillips Benefits of Water Injection - Reservoir - ii.F3 ConocoPhillips 17 Historical Context w In the 2012 hearing the reservoir engineer stated: "Therefore MI injection should remain the voidage replacement and enhanced oil recovery mechanism for the Meltwater Field until MI is no longer available from the Kuparuk River Unit. Following the Ml flood a lean gas chase may be performed to recover any trapped NGLs in the Meltwater reservoir and also water injection may be used." 40000 co 30000 Water injection rate 20000 U U c� 10000 C 0 2002 2003 2004 2005 2006 2007 2008 2009 .... IIID m1 � 1 LL N E O K Q LG in'ection rate MI injection rate 2010 2011 2012 2013 2014 2015 2016 2017 0 • • • • 0 ` YC sag OU F@20( ' 0 Y 01 2002 2003 2004 2005 2006 ZW I Nun mun Zulu Zm 1 1.11 cola .,, I �tl{' :ti Meltwater Production C OR Water injection rate MI injection rate LG iniection rate MW WI test zasoo 11000 Gay prroc�a�oor� Qa�Q 26000 10000 23400 9000 MW SI 20600 9000 test 18200 v 7000 •: 15600 a 6000 '•', :1 u. • •+ _•' 13000 '000 :•: " ' ;• • +• r,•• :: '�: :C r �,• : .' �Lt' • ,• +: * 10400 a 4000 :,• '. ••.� , • . ••. ♦ Y •_ .� 7800 3000 . * 5200 2000 ;+ 1000 '' �� Oil product on rate 2600 0 0 2002 2003 2004 2005 2006 2007 2000 2009 2010 2011 2012 2013 2014 2015 2016 }}}201 Injection Options Without Water w Lean gas ■ CPAI is currently injecting lean gas into Meltwater ■ Lean gas will not be available starting in August 2018 MI injection ■ MI will be the injection gas available to Meltwater starting August 2018 ■ MI is a valuable EOR flood mechanism ■ CPAI would prefer to put MI in new or immature wells where it can be used the most efficiently. It is not competitive to use MI at Meltwater. w Shut in production and injection ■ Either temporary or permanent w Depletion ■ Continue to produce, without injection 20 ir��,I ConomPhillips Depletion versus Water Iniection ,11 2400 " o HP o MaIRT o10ac2oon "w � 600 .................................................0............ 2000 U N 500 ,800 y Oil Production rate -water injection �'. 400 ,eoo a Mn PJM' 1200 Oil Production -depletion • - . ,000 oap dap0a400_ .......... 0 1 2 3 4 5 6 7 8 9 10 Year The sector model predicts: - Water injection would produce more oil than depletion Waterflood Enables Future Development Potential m 2015 hearing, CPAI stated 2-7 MMbbls incremental oil could be obtained through development drilling. w Waterflood keeps the field online long enough to evaluate and progress CTD development drilling 22 cw.,,3Phillips Meltwater Operations w Water will be split into two streams 1) Used for waterflooding in reservoir 2) Used only in surface facilities to keep production line warm 2N O a � a 0o a c 1 Z 3 Meltwater2131" 25 ,6 got\? 041 0p I g Meltwater I N 2P 2M CPF2 24"PO AIPL--I_---- I I �`— 10"WI(AIFL-I "4 -Comers" Intersection — — — — — Pipeline "Abandoned In Place" (AIP) Produced Oil (PO) Pipeline Gas Injection (GI) Pipeline Water Injection (WI) Pipeline Proposed iiEi?i4j4 4 ConocoPhillips 23 I a� 01 �I p 2N — 0p I g Meltwater I N 2P 2M CPF2 24"PO AIPL--I_---- I I �`— 10"WI(AIFL-I "4 -Comers" Intersection — — — — — Pipeline "Abandoned In Place" (AIP) Produced Oil (PO) Pipeline Gas Injection (GI) Pipeline Water Injection (WI) Pipeline Proposed iiEi?i4j4 4 ConocoPhillips 23 Injected Fluids Compatibility Water compatibilii w Proposed Fluids ■ KRU produced water ■ Beaufort Sea water m Meltwater flooding history ■ Meltwater flooded with KRU produced water from 2003 — 2009 ■ Beaufort Sea water used for a waterflow injection logging campaign in 2015 ■ No water compatibility issues noted w Coreflood Studies ■ Meltwater fluid sensitivity study completed in March 2001 ■ No water compatibility issues noted 5 E i; 4 a E 3 `m a 6 Effect of Various Brines on the Permeability of MWN #1, Depth 5,644.2' Flow Velocity 0.043 cm/min I No change in perm when water is switched 0 500 1000 lJuu cVW Time (min) -e-Nitrogen-8%Naa/2%CaCl2 - !<Uparuk Flood Water -� 75%Kuparukl25-/o Beaufort Seawater °�z Containment Initiatives w Containment Initiatives Required by the A10 1) Injection pressure is limited to 3400 psi at the sandface �i Continuous OA pressure monitoring • Advisory and critical alarms set to alert operators of changing pressures 3) Continued formation pressure monitoring Additional CPAI Containment Initiatives 1) Quarterly OA fluid levels 2) Bi -annual bleeds and OA gas analyses ■ Monitoring recharge rates ■ Monitoring change in composition over time Proposed Changes W No change W No change W No change W No change W Bleed as necessary, no gas samples ■ Watch OA trends, rather than recharge rates ■ Gas samples will not indicate the presence of water Subsurface Containment Assurance ConocoPhillips Subsurface Containment Assurance Standard Corporate requirement that Business Units assess and mitigate risks associated with loss of injected or produced fluids out of their intended reservoir interval or associated wellbores a Required for all ConocoPhillips operated assets W Multi -functional risk assessments of the subsurface system: geological features, wellbore integrity, operating conditions W Assessments involve geoscientists, reservoir engineers, production engineers, drilling engineers, operations staff W Subsurface Containment Assurance training required for personnel in geoscience, reservoir engineering, operations, wells, asset management roles W Subsurface Containment assessments conducted on Meltwater since 2013 W Meltwater in compliance with ConocoPhillips corporate requirements for Subsurface Containment Assurance Conclusion CPAI requests an amendment to the AlO 21B to improve the recovery of the Meltwater field by allowing Kuparuk produced water and Beaufort Sea water to be used as an injection fluid in Meltwater Oil Pool under Rule 8 By returning the field to water injection ■ It is predicted that the field life will be extended by 5-10 years which could lead to 1-2% additional recovery ■ Unlock development potential in the range of 2-7 MMBBLs ConomPhillips 29 �.
